Fortnightly - RGIhttps://www.fortnightly.com/tags/rgi
enFERC's Market Design: The End of a 'Noble Dream'https://www.fortnightly.com/fortnightly/2003/02-0/fercs-market-design-end-noble-dream
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>How state opposition cowed the feds and turned a powerful rule into just a set of talking points.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - February 15 2003</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote>
<h3>How state opposition cowed the feds and turned a powerful rule into just a set of talking points.</h3>
<p><b class="hook">A funny thing happened on the way to a standard market design (SMD).</b> What began as a full-fledged rulemaking-with the Federal Energy Regulatory Commission (FERC) giving instructions and imposing deadlines on the electric utility industry-now has degenerated into little more than a set of talking points.</p>
<p>Talk about cold feet.</p>
<p>After first asking for industry reaction by Nov. 15 and weathering a storm of protest, a chastened FERC invited a second round of comments by Jan. 10, and then extended that deadline to Feb. 28. With each round of criticism, the commission seemed to lose just a little more nerve.</p>
<p>One state, Iowa, suggested that the SMD commits such an illegal trespass on state jurisdiction that FERC would get more mileage out of the effort if it would simply cancel the compulsory aspects of the plan. The feds, said Iowa, should convert the docket (RM01-12-000) into a so-called "statement of policy"-offering only guidance to those students who might be interested.</p>
<p>FERC appeared to do exactly that, when, in mid-January, it issued a press release promising yet another white paper and-more than likely-yet another re-evaluation of the plan, followed by additional rounds of constituent feedback.</p>
<p>In short, regulators from more than a dozen states see the plan as dead in terms of regulatory discipline.</p>
<p>"Profound and unjustified," say regulators from Washington state. Solves "problems that do not exist," adds Louisiana. Regulators in Arizona call SMD "a noble dream," yet one that is "unwarranted" in its expansion of federal authority.</p>
<p>The industry appeared to have good reason to question FERC's legal authority to promulgate a new market architecture for wholesale power transactions that would bring some traditionally state-regulated features under federal purview.</p>
<p>As many parties have noted in their filed comments, the Federal Power Act bars federal intrusion into questions relating to retail electricity distribution service. They have cited that point in opposing FERC's bid to seize jurisdiction over electric transmission employed in retail service and to create a tariff with a single transmission product ("network service"). That move would de-list "point-to-point" service and kill the so-called "native load preference," whereby utilities can reserve grid capacity for the future potential use of retail customers who take electricity as a fully regulated product.</p>
<p>Indeed, the Tennessee Valley Authority argues that Congress ratified the native load preference as late as 1992, in the Energy Policy Act (sec. 212a), when it ruled that transmission (wheeling) customers must pay all costs, including costs of new facilities required for the service. TVA argues that this provision "essentially codifies the native load preference," since any existing grid capacity that has been used or relied upon to serve native load cannot be appropriated or subordinated to the wheeling request. By contrast, FERC's SMD would bar the traditional allowance for "capacity benefit margin" (CBM) to allow for future growth of native load. Instead, FERC would "monetize" CBM and put native load at risk for future load growth, by requiring retail customers who take bundled service to acquire congestion revenue rights (CRRs) to guarantee the same degree of grid access.</p>
<p>And indeed, a state public utility commission (PUC) as progressive as Pennsylvania has gone on record opposing any erosion of CBM rights, as proposed in the SMD.</p>
<p>Particularly galling to state regulators and some others is that FERC itself seems so willing to waffle on details of SMD for some beneficiaries, even while coming down hard on others.</p>
<p>For example, the commission has announced that, in the interest of moving things along, it will accept regional market models that do not mesh perfectly with the SMD. Thus, in recent decisions that approved initial plans to get regional transmission organizations (RTOs) started in the Southeast (SeTrans) and out West (WestConnect and RTO West), FERC declared:</p>
<p>"We do not intend, in the final SMD rule, to revisit prior approvals or acceptances of RTO provisions because of possible inconsistencies with the details of the final rule. This Commission intends to take all appropriate steps at the final rule stage of the SMD to ensure that, to the extent we have already approved or conditionally approved RTO elements, these approvals would remain intact." ()</p>
<p>No wonder a state like Arizona asks why, "if the SMD rule will be trumped by RTO orders," it should not be allowed to devise a unique regional solution for its own constituents.</p>
<p>These and other concerns spell a heap of trouble for FERC's SMD. The issues are numerous-far too many to be listed here-but it is possible to outline several of the most significant questions that have been raised over the past couple of months by the nation's state regulators.</p>
<h3>The Western Problem</h3>
<p>Can the Western Interconnection live with locational marginal pricing (LMP) to reconcile transmission congestion and govern a spot energy market? That question continues to divide utilities and regulators out West, with no clear resolution in sight.</p>
<p>PG&amp;E Corp., coming fresh from the California experience, where the state's independent system operator (ISO) eschewed a fully developed and security-constrained LMP model in its first disastrous fling with markets, now clearly prefers LMP, both in theory and in practice, across California and the West.</p>
<p>"There is no fundamental reason," says the company, "that makes LMP incompatible with hydro systems."</p>
<p>As PG&amp;E explains, "PJM, New York, California, and New England all have hydro resources and pumped storage facilities that operate (or will operate) under LMP electric resources."</p>
<p>The company recognizes that early debates "raised concerns about centralized unit-commitment-based designs," including "overly complex optimization algorithms, limited transparency, large uplifts and no-load costs, a consequent departure from uniform price auctions." But since then, says PG&amp;E, "the reliably successful experience in the New York and PJM day-ahead markets has lessened the scope of such fears."</p>
<p>Regulators from the state of Wyoming would appear to agree, but not so the Washington Utilities and Transportation Commission (UTC), which continues to insist, as do the utility members of RTO West, that LMP and hydro don't mix.</p>
<p>The reasons lie with the unique topology of the Western grid. As explained by the utility participants in RTO West, the regional grid system sports a Jeckyll-and-Hyde personality. The system is not homogeneous. On one hand, the companies say, the West enjoys a "relatively robust grid system" strung out along the length of certain major river systems. Beyond that, however, the remaining grid system is best characterized as "relatively lean."</p>
<p>The robust half of the Western grid does a good job of integrating the high-capacity (but energy-constrained) hydro resources located in those valleys, allowing highly efficient regional planning. The other half, however, delivers energy from remote thermal baseload plants, such as the coal-fired plants located in the eastern part of the RTO West region. It is marked by relatively expensive long-haul lines designed "to just fit" the local load or generating plant, spanning a region with a sparse population. These lines could just as well be classified as generation assets for rate-making or allocation. In no way do they resemble the spider-web sort of pattern that you would see in an integrated grid system back East. In many instances, the companies say, the grid owners and operators must pay close attention to specific local generator characteristics (voltage, VARs, output levels, remedial action schemes, etc.), just to support the transmission capability into, out of, or through the area.</p>
<p>These two bifurcated grids, the companies say, have encouraged a highly complex structure of bilateral transmission contracts that carry physical rights and maximize system performance. The structure has led RTO West to propose a variant at odds with SMD, whereby the region "catalogues" physical rights and allows participants to choose if and when to convert those physical rights into financial congestion rights ("financial transmission options"-FTOs-in Northwest parlance).</p>
<p>If these contracts were abrogated, the companies say, and if all physical rights were redistributed as financial congestion rights, whether as full FTO "strips" or chopped into hourly pieces, then contract rights holders would be certain to see a significant reduction of their pre-existing rights. The whole, then, is greater than the sum of the parts. Full conversion of physical contract rights into financial hedging rights would cause short-term transmission revenues to fall, making it difficult for transmission owners to recover fixed costs and creating "a substantial cost shift" among grid owners in the RTO.</p>
<p>Against this backdrop, the Washington UTC insists that the region cannot flourish with LMP:</p>
<p>"The hydropower system offers great dispatch flexibility. … This is already our most cost-efficient dispatch, since the hydropower system has no direct marginal fuel costs. LMP, transmission congestion pricing, day-ahead markets, single-system dispatch, and mandatory real-time balancing markets could, in theory, be implemented in the Pacific Northwest, but to what purpose?</p>
<p>"Worse yet, the [SMD] provides no assurance that the flexibility benefits of the hydropower system in the Pacific Northwest will not be lost under the proposed congestion management and CRR mechanisms."</p>
<p>In particular, the UTC chafes at claims by FERC staff that New Zealand makes LMP work with its largely hydro system. As Washington state points out, New Zealand can dispatch its hydro plants more or less independently, while most hydro plants in the Pacific Northwest are placed along a single river system and "cannot be operated independently or pitted in competition with each other."</p>
<p>Yet they see things differently in Wyoming.</p>
<p>"We generally favor the Commission's LMP approach," says the Wyoming PSC.</p>
<p>"Although some in the West argue that an LMP approach … is incompatible with the West's historic operating protocols (particularly in the Northwest) we believe LMP is central to effectively managing congestion.</p>
<p>"Although it will not be a simple task, we believe that the West will ultimately reach agreement on an LMP method that substantially preserves the principles articulated by the FERC in its SMD."</p>
<h3>Mitigating Unlawful Prices</h3>
<p>In its SMD rule, FERC proposes four remedies to mitigate anticompetitive activity and keep power prices reasonable:</p>
</p>
<ul>
<li>A bid cap in centralized spot markets to offer an overall safety net, such as the cap of $1,000 per megawatt-hour (MWh) now in place in ERCOT and Eastern grid regions;</li>
<li>A resource adequacy requirement for retail utilities, similar to the traditional reserve margin;</li>
<li>A voluntary price mitigation scheme, such as the automatic mitigation procedure (AMP) in place in the New York ISO, which compares bidding conduct to historical bid reference levels, and evaluates the impact of outlier bids on prices; and</li>
<li>Some form of must-run regime for generating plants that might exercise market power within a local area ("load pocket") plagued by transmission constraints.</li>
</ul>
<p>Though this rule might appear simple, it has raised questions among state regulators. Should price mitigation schemes recognize the right of power producers to recover not just variable and fixed costs, but opportunity costs that reflect scarcity rents collected during periods of regional supply shortages, as FERC has proposed? Connecticut regulators say yes (with scarcity value based on the highest-cost losing bidder), but others disagree.</p>
<p>Some states, such as Wisconsin, call for market mitigation for bilateral trading, as well as for centralized spot markets, as FERC has proposed. In similar fashion, regulators at the Connecticut and the New England PUC association (NECPUC) urge FERC to extend mitigation beyond cases involving transmission constraints or local market power to cover situations such as extreme demand peaks, in which virtually all regional units are dispatched, and suppliers can take advantage, knowing that grid operators must dispatch nearly all bidders.</p>
<p>The New England regulators fear market power "even in areas free of transmission constraints," and they describe the current safety net bid cap of $1,000/MWh as "wholly inadequate" to protect consumers. Georgia regulators share that view:</p>
<p>"The idea of FERC imposing a system of electricity price regulation on Georgia and the Southeast where caps of $1,000 are deemed a necessary part of the FERC systems sets off alarm bells."</p>
<p>Nevertheless, NECPUC admits that FERC gave fair warning last fall in a case that reviewed market design in ISO New England, when it asked the ISO to explain why a safety net bid cap of $1,000/MWh would not provide sufficient consumer protection in areas without transmission constraints. .</p>
<p>Policy disagreements can emerge even in regions with a lot of spot market experience.</p>
<p>In PJM, for example, market rules trigger mitigation in either the day-ahead (DAM) or real-time markets whenever and wherever an interface constraint creates a local load pocket that requires generation to be dispatched out of merit order. Once triggered, the plan will mitigate bids for must-run plants operating within the load pocket, usually by reducing the nodal clearing price to a level equal to the generator's estimated incremental cost, plus 10 percent. The Maryland People's Counsel praises the PJM method and urges FERC to incorporate it in the SMD for load-pocket relief. (PJM also allows other alternative mitigation options for load pockets: either a simple price negotiation, or a reduction in the clearing price to the level of the average of LMPs at the same generator bus for hours that featured a merit-order dispatch.)</p>
<p>One might think PJM would serve as an exemplary model for FERC's SMD. Especially here, where the SMD lays down a heavy hand to keep prices low. But it seems that FERC can't win for losing, because even in this case, state regulators in PJM's home state of Pennsylvania actually would prefer a different rule-one that would adopt less of a regulatory approach and more of a competitive or market solution.</p>
<p>Of course, the Pennsylvania PUC acknowledges that some have proposed to improve the PJM rules by substituting some sort of guaranteed generator payment reflecting variable and fixed costs plus a rate of return. But again, the PUC sees such solutions as so much "formula tweaking, headed in the wrong direction towards more RTO rate setting, rather than less."</p>
<p>For its part, the Pennsylvania PUC would prefer some sort of "proxy competitive price," derived either from historic unconstrained hours in the region on different days, or proxy LMP prices for the hour in unconstrained regions outside the load pocket (or perhaps even the historical average successful LMP bids by the generator itself, during unconstrained hours, which would have the effect of making the unit its own price proxy).</p>
<p>The point, says the PUC, is to avoid an "irrationally generous" mitigation scheme that destroys any incentive for efficient plant operation by setting an administratively mitigated price that still exceeds the plant's incremental cost by a substantial margin.</p>
<p>Otherwise, the PUC says, such plants could still operate, despite mitigation, as "the only big fish in the local pond, sure of a risk-free market for power, and fiercely contesting any new entrants."</p>
<h3>Funding Transmission Expansion</h3>
<p>Politics makes for strange bedfellows. As an example, consider that many of the states that oppose FERC's SMD plan most ardently-Georgia, Arkansas, Kentucky, North Carolina-are themselves some of the biggest boosters of perhaps the most progressive element of the plan: participant-funded transmission (PFT), which calls on merchant generators to pay for grid expansion in place of rolled-in pricing. Indeed, these states typically will defend PFT as an essential adjunct to an LMP congestion pricing system, so as not to distort price signals. Kentucky has even passed a state legislative resolution endorsing PFT.</p>
<p>"Participant funding leaves decisions over 'economic' grid upgrades to free market forces," says the Arkansas commission. "This allows for full and fair competition between generation, transmission, and demand-side resource solutions to congestion."</p>
<p>At the same time, however, these states fervently oppose LMP and market pricing for energy as unworkable for their own constituents. Meanwhile, the states that prefer traditional rolled-in pricing over participant funding, such as North Dakota, tend also to favor postage-stamp pricing over license-plate pricing.</p>
<p>States in the West and the Great Plains generally prefer socialization of grid expansion costs over the broadest possible region, as they must seek to open up their resources to boost power exports to urban consuming areas. In the words of the Crescent Moon grid group, they fear that FERC may be "backsliding" in favor of license-plate pricing and ignoring its original vision of wide-area, pancake-free pricing.</p>
<p>The Louisiana PSC has panned SMD outright. It sees disaster in any mandatory plan to force utilities to divest themselves of transmission assets to form independent transmission providers (ITPs), as FERC would require through its market design. Yet two Entergy utility subsidiaries, in a pending case in that state (La. PSC Docket No. U-25965), have offered studies showing that any plan for them to join either SeTrans (planned as an RTO) or the Midwest ISO (already RTO-certified) will likely increase costs unless the deal is coupled with a PFT policy that compels new merchant generators to pay for grid expansions they need for new power plants. The plan offers an alternative to traditional rolled-in pricing, which would impose the costs of such expansion on retail ratepayers of transmission-owning utilities.</p>
<p>In a similar example, the Southeast Association of State Utility Regulators (SEARUC) commissioned a study from Charles River Associates that found virtually no consumer benefits from a SeTrans RTO without participant-funded transmission.</p>
<p>FERC indicates a willingness to allow participant funding, but only for new transmission facilities that are included in a regional planning process conducted by an independent grid operator, be it an RTO, ISO, or ITP. And therein lies a key issue: Can participant funding exist on its own, outside the rest of the SMD framework?</p>
<p>In Arkansas, the commission says there are times when participant funding needs to be supplemented by transmission planning studies, and when rolled-in pricing might be warranted "on a limited basis." For example, a grid expansion plan funded by one merchant generator might end up benefiting several such new plants in the same region. In that case, Arkansas says, the ITP would need to develop a cost-sharing protocol applicable to all merchant plant beneficiaries.</p>
<p>Consider another example offered by Arkansas regulators:</p>
<p>A new merchant power plant might require a network upgrade, achievable with a new line with capacity of either 138 kV or 230 kV. This merchant plant might well choose to select the smaller upgrade in order to leave some congestion intact and optimize the value of CRRs, even if the 230-kV option would eliminate 100 percent of the congestion (driving CRR values to 0) at only a slightly higher construction expense.</p>
<p>"In such a case," says Arkansas, "the ITP may wish to require the 230-kV expansion option but only charge the merchant plant for the suboptimal 138-kV cost. The difference in cost … would be rolled-in or reallocated. The final [SMD] rule should allow for such modifications to the pure participant-funded structure (as part of an RTO-ITP-approved transmission plan)."</p>
<p>Nevertheless, regulators in North Carolina (another pro-PFT state) oppose FERC's RTO/ITP overlay as a requirement for participant funding. North Carolina sees an immediate need for a new transmission expansion policy that does not involve socialization of costs. Participant funding, says North Carolina, "is unrelated to the existence of independent operation of the transmission system … so that implementation should not depend on the existence of an ITP."</p>
<p>Of course, there is more going on here than meets the eye. The planned SeTrans RTO has invested a lot of planning effort in reliance on participant funding as a viable new policy to avoid forcing transmission owners to foot the bill for grid expansion designed to accommodate new local generators, only to see the local power exported out of the region.</p>
<p>In fact, the Pennsylvania PUC has observed that participant funding has become a two-edged sword. As the PUC explains, it sounds like a free market idea, but it can easily be turned into a weapon (a "cudgel," Pennsylvania says) against the introduction of competitive markets. Perhaps there is a little bit of that going on in the states that have embraced participant funding, yet have rejected LMP and SMD, as the Pennsylvania commission hints in its SMD comments filed Jan. 10:</p>
<p>"Participant funding, raised as a high-level issue primarily by some states and stakeholders in the Southern and Northwestern U.S., has been a flashpoint for criticism of the proposed standard market design. … Typically, the issue has been framed as [one] of fairness. … But the concept … may enable the remaining incumbent vertically integrated monopoly electric utility companies to disadvantage new market entrants and potential competitors.</p>
<p>"Incumbent utilities, having built the existing transmission grid, are likely to be entirely satisfied with its topology and transfer limits.</p>
<p>"Participant funding as a general principal of SMD … would enable the incumbent monopoly utility to protect its own generation business."</p>
<hr />
<hr />
<h3>Learning from comments filed by state utility regulators in FERC's SMD case.</h3>
<p><b class="hook">ARKANSAS-CONGESTION UP?</b></p>
<p>Notes that PJM has reported dramatic increases in congestion charges even as its bid-based market has developed, with costs rising from $53 million in 1999 to $271 million in 2001, a more than five-fold increase. Compare that situation to the recent study conducted by Charles River Associates, which estimated intrazonal congestion charges at $200 million a year for the planned SeTrans RTO, and $475 million annually for the entire Southeast region, plus an additional $260 million annually for interzonal and export congestion fees.</p>
<p><b class="hook">CALIFORNIA-BETTER BOARDS.</b></p>
<p>Warns that FERC's selection process for RTO board members could produce a "moral hazard." Notes that under FERC policy, the boards of the four existing "stakeholder" RTOs (MISO, PJM, New York, New England) have come to be made up 50 percent of former utility executives, a significant number of whom are retired. An added 8 percent had substantial utility ties (consulting, etc.), while 21 percent came from finance and 6 percent from an information technology background. A cursory review showed less diversity of experience on RTO boards than for traditional utilities.</p>
<p><b class="hook">ILLINOIS-LET FERC BE BOSS.</b></p>
<p>Wants market monitoring (MM) staff at RTO or ITP to function as contract agent of FERC, and be funded through a mechanism that remains separate from the RTO/ITP funding protocol. "It is simply not reasonable to expect the MM to be accountable to the FERC and independent of the RTO, under a framework in which the MM is selected by the RTO, contracts with the RTO, has its budget set by the RTO, has terms of payment controlled by the RTO, and has its invoices paid by the RTO."</p>
<p><b class="hook">KENTUCKY-WATCH PAYROLLS!</b></p>
<p>State regulators warn that FERC policy already is taking a "toll" in Kentucky, as retail rates there are likely to rise in tandem with the tens of million of dollars in extra administrative costs incurred annually at the Midwest ISO. "With an annual operating budget approaching $70 million, a capital budget of more than $30 million, and a staff of 210 people, MISO is clearly not an inexpensive undertaking."</p>
<p>Kentucky also is a party to a legal appeal in the federal courts (Midwest ISO Trans. Owners v. FERC, Case Nos. 02-1121, 02-1122, D.C.Cir.) that seeks to overturn a FERC ruling that rejected a settlement between MISO and the Kentucky PSC that would have saved the state's native load customers from paying MISO administrative costs.</p>
<p><b class="hook">MAINE-RESERVE MARGINS?</b></p>
<p>State opposes the new resource adequacy requirement (RAR) contained in the SMD. It argues that FERC's plan for a 12 percent margin, as measured against retail "load," cannot work, because in states that have moved to retail access, the retail supplier no longer has any captive load. Maine PUC says that retail suppliers could avoid FERC-imposed penalties for failure to maintain the required margin simply by exiting the market prior to "real time," in effect ignoring the RAR rule entirely.</p>
<p>The PUC proposes instead to adopt a structure that it calls a "central buyer model," whereby the RTO/ISO/ITP determines the capacity required for the market as a whole through an auction, and then buys the commitments needed to provide that product for the relevant period. There would be no direct link between any particular load and any particular capacity; that would be "impractical and illogical," the PUC says.</p>
<p><b class="hook">OHIO-FULL DISCLOSURE, NOW.</b></p>
<p>Says states lack access to data needed to make market-monitoring work on all levels. Notes that PJM has a 6-month moratorium on release of MM information to state regulators, and then can release only the fact of market abuse-not the identity of the culprit. Says New York has a three-month moratorium, while New England keeps information confidential for seven days. By contrast, the Midwest ISO prohibits all state regulatory access to MM information, forever. "This situation is unconscionable," says Ohio.</p>
<p><b class="hook">TEXAS-CALIFORNIA REDUX?</b></p>
<p>As the PUC explains, ERCOT lacks a day-ahead energy market (DAM) and in the past has tried to manage congestion on a zonal basis (as California tried to do and failed).</p>
<p>Now, however, the PUC claims that its Market Oversight Division has developed and implemented a system for congestion management that is based not on nodal locational marginal pricing (LMP) but on an administrative assignment of hypothetical congestion charges needed to achieve a pre-determined, formulaic optimization of the transmission grid.</p>
<p>Texas fears that, like California, zonal congestion management method in ERCOT has led to a "dec game" (manipulation of decremental bids). Also, a huge amount (nearly 900 MW) of wind-powered generators has located unexpectedly in West Texas, on the wrong side of a major local transmission constraint, in reliance on faulty locational market signals supplied by the old zonal congestion system.</p>
<p>The PUC now says it has visions of creating an energy DAM with ex- ante pricing that would be operated privately, because with its newfangled congestion management system, the DAM could receive bids and execute dispatch without a security-constrained protocol. <b></b></p>
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Sat, 15 Feb 2003 05:00:00 +0000puradmin11160 at https://www.fortnightly.comNeptune and the Northeasthttps://www.fortnightly.com/fortnightly/2001/09-0/neptune-and-northeast
<div class="field field-name-field-import-deck field-type-text-long field-label-inline clearfix"><div class="field-label">Deck:&nbsp;</div><div class="field-items"><div class="field-item even"><p>What a merchant transmission line &lt;br&gt; could bring to the table&lt;font color=&quot;000066&quot; face=&quot;Arial, Helvetica, sans-serif&quot;&gt;.</p>
</div></div></div><div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Edward Krapels</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - September 15 2001</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><blockquote><h2>Neptune and the Northeast </h2>
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<h3>What a merchant transmission line <br /> could bring to the table<font color="000066" face="Arial, Helvetica, sans-serif">. </font></h3>
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<p> <b>It' s been a couple of busy weeks in the transmission arena back at the Federal Energy Regulatory Commission (FERC). </b></p>
<p>On July 12, it herded the transmission owners into a big corral, where New England, New York, and PJM independent system operators would join forces to create a single, super-RTO (regional transmission organization). Then, two weeks later on July 25, it set the proposed Neptune transmission project loose in that corral. The sponsors of the Neptune project, known formally as the Neptune Regional Transmission System, would build a 4800-megawatt high-voltage direct current (DC) transmission network, connecting Atlantic Canada with NEPOOL, the New York Power Pool, and PJM. </p>
<p><b>BY CONNECTING GENERATORS IN RELATIVE REMOTE AREAS WITH LOAD IN RELATIVE CONGESTED URBAN AREAS, THE NEPTUNE PROJECT WOULD FORM THE BACKBONE FOR AN EMERGING NORTHEAST RTO.</b> FERC's order directs the Neptune project to work with a future Northeast RTO to ensure that the RTO's tariff would be designed in a manner that would accommodate the Neptune project' s financing needs. That is an important statement. It is directed not just at the Neptune project, but also at the parties creating the Northeastern RTO. As FERC explained in its July 12 order calling for a Northeast RTO, "our long-term competitive goals are better served by RTO expansion plans that allow for third-party participation as well as merchant projects outside the plan." It ordered PJM to revise its procedures "to include in its process that third parties may participate in constructing and owning new transmission facilities." </p>
<p>Thus, the regulatory doors have swung open to merchant transmission. Can the Neptune project meet the challenge? </p>
<p><b>CONSIDER NEW YORK CITY. WHILE IT MAY WELL BE POSSIBLE TO SHOE-HORN ONE OR TWO NEW 1000-MW POWER PLANTS INTO THE CITY, </b>and to re-power one or two existing plants, in the long run a new paradigm has to be found.</p>
<p> In fact, several years of location-based marginal pricing experience in PJM and the New York Power Pool provide ample evidence of the existence of an urban price premium for electricity. During the period from June 1, 2000, to May 31, 2001, the average price in Zone J was more than $20 higher than that of the PSE&amp;G zone just across the Hudson River. </p>
<p>Regarding the urban premium, New York and Boston now represent mixed gas/oil markets with lots of old and inefficient generating units - hence the high clearing prices in energy markets. Over time, most of the oil-fired capacity will be phased out, and a few new combined-cycle natural gas turbines (CCGTs) will be installed. But neither city is likely to be the home of surplus electricity generating capacity. Relatively tight capacity markets means enduring urban premiums for energy and capacity, compared to surrounding suburban and rural areas. </p>
<p><b>BY CONTRAST, NOVA SCOTIA GENERATORS CAN ACCESS EX-TARIFF SCOTIAN SHELF GAS, FOR AN ADVANTAGE OF UP TO $10/MWH. </b>New Brunswick has excess existing hydro, coal, orimulsion, and nuclear power in the summer, which will usually be cheaper than gas-fired power in Boston or New York City. Building a new CCGT in Nova Scotia, New Brunswick, or Maine is likely to be 15 to 20 percent cheaper than building in New York or Boston, and is unlikely to be levied a stiff interconnection charge, which is likely in the cities. Generators in the North are likely to have to buy fewer (if any) emission credits, and to incur less (if any) summer de-rating. These cost differences - the same dynamic that makes a brownstone in Manhattan cost more than the same one in Jersey City - will prove very substantial. </p>
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<a href="/tags/ccgt">CCGT</a><span class="pur_comma">, </span><a href="/tags/ces">CES</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/dc">DC</a><span class="pur_comma">, </span><a href="/tags/der">DER</a><span class="pur_comma">, </span><a href="/tags/fcc">FCC</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission-ferc">Federal Energy Regulatory Commission (FERC)</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/gas">GAS</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/neptune">Neptune</a><span class="pur_comma">, </span><a href="/tags/nera">NERA</a><span class="pur_comma">, </span><a href="/tags/ors">ORS</a><span class="pur_comma">, </span><a href="/tags/ot">OT</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/pseg">PSE&amp;G</a><span class="pur_comma">, </span><a href="/tags/rgi">RGI</a><span class="pur_comma">, </span><a href="/tags/rto">RTO</a><span class="pur_comma">, </span><a href="/tags/scotia">Scotia</a><span class="pur_comma">, </span><a href="/tags/transmission">Transmission</a> </div>
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Sat, 15 Sep 2001 04:00:00 +0000puradmin10539 at https://www.fortnightly.comMailhttps://www.fortnightly.com/fortnightly/1998/11/mail
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>David A. Foti, Robert G. Schoenberger, Richard M. Chapman, Pat Boland</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - November 1 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> THE SEPT. 1, 1998 ISSUE OF Public Utilities Fortnightly contained an article, "The Fortnightly 100," which promised to reveal America's "most efficient utilities." The authors used data envelopment analysis (DEA) to analyze historical operating and financial data for 140 utility holding companies. While DEA can be a useful tool for data analysis, used indiscriminately it can lead to misleading conclusions. </p>
<p> There are several rules of thumb to consider when benchmarking utilities, which were not incorporated in determining the "efficient" utilities from the ones who "misallocated" their resources. </p>
<p> Typically, when utilities benchmark against each other they create benchmarks for comparison that match generation costs to generation cost drivers (e.g., MWh produced), transmission costs to transmission cost drivers (e.g., mile of transmission lines) and distribution costs to distribution cost drivers (e.g., number of customers). </p>
<p> In their study, the authors only used one cost driver, MWh produced, to determine a company's efficiency. This methodology adversely biases the results of any utility whose company-owned production is relatively small compared to its transmission and distribution network. An example of this could occur in the case of a utility that divested the majority of its generation assets in favor for purchased power contracts. </p>
<p> The purpose of benchmarking, as the authors note, is to give companies an idea how much they can improve their current operations. Therefore, the analysis should be normalized for exogenous or uncontrollable factors. Some examples include: </p>
<p> • Asset Mix. The authors, without hesitation, compare all-fossil generation utilities against utilities with nuclear generation. An all-fossil utility will almost always look better than a utility with nuclear assets. Very little of that difference has anything to do with which utility is employing "best practices" as the authors suggest. </p>
<p> • Geographical Location. If the authors wanted to include fuel costs in their analysis, then it is difficult to see why they chose to compare utilities in producing regions against utilities in market areas. Transportation cost for fuel can be significant. Transport for coal can easily be as much or more than the coal itself for a plant not located near the mine mouth. Transport expense for gas in a heavily consuming region like the Northeast can reach 60 cents/ mmbtu (firm) or approximately 30 percent of commodity cost versus 10 cents/mmbtu for a power plant in Texas. </p>
<p> • Urban Versus Rural Utility. Urban utilities tend to have higher operating and maintenance and capital costs since maintenance and construction on a city street is much more expensive then trenching in a field. Also, an urban utility is likely to have more underground lines - more expensive than above-ground lines at </p>
<p> a rural utility. </p>
<p> While using historical databases for source data is convenient, there's always the chance of not fully understanding what is behind the numbers. For example, the authors included pension costs in their analysis. As a result of FAS 106 (an accounting rule requiring fully funded pensions), some utilities that were underfunded in the past will show a very high pension expense as they ramp their pensions up to fully funded status. The additional pay-in some utilities are making as a result of FAS 106 is significant, sometimes up to 10 percent of total labor costs. </p>
<p> Not adjusting for unique characteristic of some utilities is another instance of reaching questionable conclusions by using numbers without fully understanding them. For example, since reliability is seen as extra critical by the businesses in Manhattan (especially in the financial sector), Con Edison in New York has designed and operates an extremely high reliability system, which is relatively expensive to maintain. The authors ignore the special conditions companies like Con Ed operate under. They label the additional costs "misallocated." </p>
<p> While the SEC data the authors used is likely to be accurate and representative, caution should be used in drawing conclusions from FERC Form 1 data. While the FERC has set out detailed account descriptions and instructions for the population of these forms, there exists variability in the conformity of how utilities categorize their costs. </p>
<p> Additionally, and perhaps more significantly, each utility has discretion in what level of capitalization they apply to their overall costs to get the split between O&amp;M expense and additions to capital (rate base). Differences in capitalization rates can significantly affect comparisons that include O&amp;M. </p>
<p> Company benchmarking, at its best, exists in the form of benchmarking consortiums. In a benchmarking consortium, a number of companies in the same industry agree to provide very specific information to an impartial third party, such as an accounting firm or consultancy. The third party expends a considerable effort to assure comparability of the source data, normalize for one time or unusual costs, and select appropriate peer groups. The McKinsey Gas Pipeline Benchmarking Study and the Arthur Andersen E&amp;P General and Administration Expense consortiums are good examples of this type of study. </p>
<p> Recognizing that limited resources may prevent such detailed analysis, large broad-based studies can be useful - only if these benchmarking "rules of thumb" are addressed. </p>
<p> David A. Foti </p>
<p> Economic Adviser </p>
<p> Enron Transportation and Storage (Gas Pipeline Division) </p>
<p> Enron Corp. </p>
<p> Houston </p>
<p> The writer has worked as an energy consultant for some of the "Big Five" firms and has performed more than a dozen utility benchmarking studies. </p>
<p> I WAS AMUSED TO READ THE ARTICLE ON UTILITY "EFFICIENCY" in your Sept. 1, 1998 issue. It reminded me of the weather reports we often get from so-called experts who haven't bothered to look out the window to see what the sky is doing. Econometric analysis is a difficult and challenging endeavor, one which can have great value in helping businesses and policy makers make the best decisions. The more elaborate and difficult the analysis however, the greater the danger in drawing conclusions that have no practical basis or use. This is in fact the case with the analysis presented - an elaborate and rather elegant theoretical study of "efficiency" in the utility sector, the results of which are totally useless. </p>
<p> The clue to this flaw is found in footnote 4, where the authors admit that "we may have introduced some bias against companies with large amounts of purchased power." In short, the study adopts as a key assumption the simplistic notion that each utility in the entire industry reflects an identical degree of vertical integration. </p>
<p> Talk about bias! It works against regions and companies with significant generation from independent power producers, and regions with very active bilateral markets. It also is biased against companies that use the competitive wholesale market as an efficient and cost effective way to meet power requirements. Finally, it counts against utility systems divesting of generation in response to state restructuring initiatives. </p>
<p> For example, Unitil is a small holding company system in New England, which operates three distribution systems, two in New Hampshire and one in Massachusetts. Unitil owns less than 10 percent of its generation requirements, having found that competitive wholesale purchases in New England are far more cost effective to meet customer requirements than building and financing generation. As a result, Unitil has among the lowest rates in New England. On the other hand, Unitil is also a very efficient distribution company. Analysis of the costs of distribution among New England utilities reveals that Unitil's distribution operations are the most efficient, and most cost-effective in the region. But you would never know it from this study. </p>
<p> It is likely that economics will continue to be known as "the dismal science" as long as its practitioners continue to forget the basic requirement of science - to observe the real world. </p>
<p> Robert G. Schoenberger </p>
<p> Chairman/CEO </p>
<p> Unitil Corp. </p>
<p> Hampton, N.H. </p>
<p> THE OBJECTIVE OF THE AUTHORS OF "THE FORTNIGHTLY 100" - to provide comparative measures of efficiency among electric utility companies - is a laudable one. We at Vermont Electric Power Co. have devoted considerable effort to this task because we agree that "Things that are measured tend to improve." </p>
<p> As a company that provides transmission only, we have been hampered by a lack of comparable data, so we have been limited to measurements of changes in (1) the price we charge for our services, and (2) the reliability and quality of service we furnish. During the past 10 years, the price we charge for our services has remained essentially flat, while the regional producer price index has risen more than 25 percent, and the consumer price index, more than 37 percent. Pursuing a zero defect policy, we also have seen a steady trend of increased reliability and quality. </p>
<p> We were astonished, therefore, to find ourselves posted at the very bottom of the article's top 100 companies. Notwithstanding their praiseworthy objective, your authors committed the error of failing to understand the data they used in their analysis. They define the output side of their efficiency formula as "total physical production in megawatt-hours produced and sold to all sectors." Data regarding production and sales were then taken from FERC Form 1. Owing in part to the inflexibility of FERC reporting requirements, and in part to some unique contractual arrangements, VELCO does report megawatt-hours sold to FERC. The fact is, however, that we are strictly a transmission company. We produce no power and, except via paper transactions as a pass-through entity, we sell no power. In short, the data employed by the authors of the article were, for VELCO, absolutely meaningless. </p>
<p> The authors may or may not have produced a useful tool for utilities to compare and improve their performance, but they have certainly not found a way out of the data age adage, "Garbage in, garbage out." </p>
<p> Richard M. Chapman </p>
<p> President/CEO </p>
<p> Vermont Electric Power Co. </p>
<p> Rutland, Vt. </p>
<p> THE AUTHORS RESPOND: We appreciate the interest our article generated. The impetus for this paper came from the authors' interest in and experience with productivity measurement and analysis over several years. With the advent of competition in the electric utility industry, and the obvious effects of productive efficiency on the competitive position of utilities, it seemed rigorous studies of productivity using the available tools would be needed more than ever. The two studies we published in the past year (Public Utilities Fortnightly, Sept. 1, 1998 and June 15, 1997), and the interest they generated indicate this is indeed the case. </p>
<p> Our analysis was intended as a macro-level general model to demonstrate how raw data envelopment analysis (DEA), a linear programming approach, can be used as an alternative to the econometric methods in measuring operational efficiency across a large group of enterprises. We received many favorable responses and a few critical ones. Potential bias, resulting from some inherent heterogeneity in the population of utilities that we studied was the main critical theme in the majority of unfavorable responses. Variations among utilities in the mix of generating resources, in geographic location, in consumer density, and in the proportion of purchased power, were the main sources of bias mentioned. </p>
<p> At issue is whether such heterogeneity invalidates efficiency comparisons across utilities. Indeed, heterogeneity, a fact of life, necessitates the use of techniques such as DEA, which allow us to make efficiency comparisons across different technologies and input mixes. The DEA approach produces a ranking of efficiency scores based on "relative" performance to "peers." That is, efficiency of any particular utility is examined vis-à-vis other utilities that are alike in terms of input mix. The final performance ranking across utilities is, to a large extent, a function of the technology and input mix. </p>
<p> We do acknowledge, however, as noted in footnote 4 of the Sept. 1 article, that our efficiency ranking is biased against utilities with significant amounts of purchased power. Unfortunately, data limitations prevented us from performing the appropriate adjustments to eliminate such bias. </p>
<p> IN "CHARGING KWhS AND BTUS ON CREDIT," (Public Utilities Fortnightly, Sept. 15, 1998), I was taken by surprise by the comments attributed to Mychelle Jackson of Austin, Texas. She mentioned that her utility accepts credit cards for customers who have been disconnected for non-payment. I work for Northern States Power based in Minneapolis and am responsible for payment programs. NSP has been advised that accepting a credit card "on any account that has been assessed a late payment charge," would be out of compliance with Visa banking rules. We had been taking credit cards on past due bills and Visa wrote to us and informed us we were out of compliance. Obviously we discontinued the practice and the result has been many angry customers that used to use the card. It is curious that some companies continue the practice. </p>
<p> Pat Boland </p>
<p> Product Manager </p>
<p> Northern States Power Co. </p>
<p> Minneapolis, Minn. </p>
</p>
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<a href="/tags/benchmarking">Benchmarking</a><span class="pur_comma">, </span><a href="/tags/con-edison">Con Edison</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/ors">ORS</a><span class="pur_comma">, </span><a href="/tags/res">RES</a><span class="pur_comma">, </span><a href="/tags/rgi">RGI</a><span class="pur_comma">, </span><a href="/tags/sep">SEP</a> </div>
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Sun, 01 Nov 1998 05:00:00 +0000puradmin9904 at https://www.fortnightly.comInventing a Business in Wires & Pipeshttps://www.fortnightly.com/fortnightly/1998/06-0/inventing-business-wires-pipes
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Joseph F. Schuler Jr.</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - June 15 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> IF COMPETITIVE ELECTRIC MARKETS PROMISE LEAN MARGINS and slim savings on commodity sales, then perhaps transmission and distribution companies could play a larger role in selling end-user services. </p>
<p> Yet low-risk T&amp;D companies, building on their reputations as reliable providers, may need to grow to acquire the "critical mass" needed to make money selling services over delivery systems. </p>
<p> One of the few, if not only, businesses publicly betting on this strategy is the $4.1-billion GPU Inc. of Morristown, N.J. - and GPU means business. </p>
<p> The company's first step is to get out of generation. It is auctioning its share in 26 fossil and hydropower plants. The combined book value of the plants is about $1.1 billion. GPU was negotiating with a single buyer - possibly PECO Energy Co. - for its two operating nuclear generating units, including one at Pennsylvania's Three Mile Island. GPU is exiting the merchant plant business as well. </p>
<p> While it divests generation, the company is boosting its customer base overseas. It increased its end-user base by more than 17 million people by acquiring half the United Kingdom's Midlands Electricity PLC, a distribution company (sale price: $2.6 billion), and all of Australia's PowerNet Victoria, a transmission company (sale price: $1.9 billion). </p>
<p> This spring, the company was eyeing privatization opportunities in Brazil, although when Eletropaulo, Latin America's largest distributor, went on the block in April, GPU didn't have enough time to prepare financing, says William J. Dennard, company spokesman. </p>
<p> The company's goal is to acquire the profitable delivery systems of the democratic world, says a half-serious Fred D. Hafer, company president, chairman and CEO. </p>
<p> Pleasing the Shareholders </p>
<p> In reality, GPU is limited under the Public Utility Holding Company Act to investing no more than 100 percent of its retained earnings. </p>
<p> But Hafer, by helping set the global road map, is on his way within those parameters leading GPU to wherever wires, poles and pipes will go. </p>
<p> Along that path comes some predictable realizations. "The infrastructure business that we have chosen, will, by virtue of its continued regulatory oversight, have¼ modest earnings, as compared to unregulated competitive businesses," Hafer says. "They will be, by definition, regulated rates of return. We think on the other side of that, however, there's a certain predictability and stability." And some investors, he says, find that attractive. </p>
<p> In assessing GPU's return on equity for T&amp;D in the U.S., Hafer and Dan Ford of HSBC Securities Inc., offer the same evaluation: With flat inflation and steady interest rates, investors can expect an 11.5 percent ROE. On non-U.S. investments, Hafer puts ROE at 15 to 17 percent. </p>
<p> GPU's announcements haven't hurt its standing in the financial community, notes Frank M. Heard of Arthur D. Little Inc. "If you look at GPU's stock performance [in mid-April], it's holding up pretty well," he says. "It's near a 52-week high. The strategy is out there. Wall Street seems to be rewarding that. I think the reason they're rewarding the company strategy is because it is well articulated. </p>
<p> "They've got a multiple on earnings of about 16 times earnings right now," Heard adds. "Which is in the ballpark of other companies who have taken - or at least announced - different strategies, such as Florida Power &amp; Light and PECO Energy." </p>
<p> Ford says a string of events have made it possible for GPU to come out ahead in its strategy. The debacle of Three Mile Island forced GPU to make TMI one of the best-run plants in the U.S., although it will have to tend to the downed TMI-2 reactor. That reactor could cost GPU $400 million through 2014, including decommissioning expenses, according to its 10K Form. After the TMI accident, the company simply didn't build much generation, Ford notes. It entered purchased power contracts for most of its supply with non-utility generators at fixed prices. </p>
<p> More recently GPU looked at its generation portfolio and saw little there that compared with neighboring utilities and the "Duke Powers" of the electricity world. </p>
<p> "So the decision was simple," Ford says. "There's also a very good sellers market for generation right now. So part of the attraction is, first of all, I don't have enough to be a critical size. Number two, by divesting it, it's probably going to help with my transition plan with my regulators because they'd probably like to see less market power as opposed to more¼ [I]t's probably worth more to someone else." </p>
<p> "Finally, if I can redeploy that cash in a strategy on a transmission-distribution side, or in just simply financial restructuring while lowering my risk profile, there's probably shareholder value in it." </p>
<p> Hooking the Customers </p>
<p> As GPU carries out its strategy, the question becomes: How will it leverage its brand name if wires services remain regulated? Can it parlay its links to customers (through a regulated distribution network) to sell unregulated revenue-cycle services to bolster its average ROE? Furthermore, how many links will be needed to make those sales profitable? </p>
<p> An answer to those questions may partially lie in GPU's branding campaign, in which it claims it's "Inventing the Future of Energy." The campaign is being carried out via major newspapers, cable TV and on the backs of transit buses. </p>
<p> Hafer believes there's benefit "at this stage of the evolution," to keeping the GPU name in front of the public. "Particularly as they are beginning to hear other, strange names that are coming into the area - such as an Enron, such as a Southern Company¼ we need to keep reminding them that GPU is their power company." </p>
<p> Ford says he suspects this tactic isn't done because GPU wants customers to feel good about the monopoly. "Eventually they want to sell them other 'stuff.' That's where the premium returns reside." </p>
<p> If regulators allow holding companies like GPU to use their "brand" names, it could change ROE tremendously. </p>
<p> Says Ford: "That's a question¼ You don't have to be under the same umbrella to do the cross-selling. You can have a non-regulated subsidiary that sells 'xyz' widget that you think would be useful." </p>
<p> "To date, the regulators in the two states we have our primary business in, Pennsylvania and New Jersey, have not indicated any problem with us continuing to use our corporate name in another subsidiary of GPU," Hafer says. "And I am not expecting that there would be any prohibition against that." </p>
<p> The CEO says GPU will leverage its corporate name by being a "world class" provider in the regulated side of the business, under the name of GPU Energy, or GPU PowerNet or some other GPU T&amp;D moniker. Then, it will be recognized for superior performance when it comes knocking on the door as an unregulated services provider. The unregulated GPU Advanced Resources company is participating in Pennsylvania pilot programs in retail sales, among other activities. </p>
<p> "I believe that as long as the companies, such GPU and other currently regulated companies, don't do anything foolish - that is, continue to play in an open and fair way - that there's no reason we should be prohibited from using our name," Hafer says. He says if GPU can provide more products and better service at lower costs, "God bless them. And that's what the regulators and the legislators and the customers should want. And if it's Enron that comes in and can do it, then so be it." </p>
<p> However, at press time, it looked like the only place Enron Corp. was going was out of the states that promised "regulated" and costly competition, including GPU's home state of New Jersey. </p>
<p> Limited by Numbers? </p>
<p> Hafer suspects that T&amp;D companies will have to be larger than the 2 million customers GPU now claims in the U.S. to continue doing business. </p>
<p> "I believe just the pressures, the political, regulatory, governmental pressures that will be brought to bear as the economies and services of the larger companies become obvious will make it very difficult for the smaller companies to stay in business," he says. "Clearly, 2 million customers, in my mind, is not big enough. The question that everyone keeps wrestling with, though is: What is big enough? There seems to be a consensus opinion building that probably 10 million is big enough, that anything more than 20 would be too big¼ I don't know that there's any real analysis that goes along with that." </p>
<p> "Ten million customers is no magic number," says Ford. "If, however, you're going to use that distribution system and that relationship¼ to sell them other 'stuff,' then the number of customers is very important." </p>
<p> To some degree, Hafer says, the numbers will be driven by who is handling revenue-cycle services. Will the delivery companies continue to be the companies that have the call centers, the billing centers and the meter readers, or will those be contestable services that might be handled by non-utility organizations? </p>
<p> Hafer believes there are too many distribution companies in the U.S. "You don't really have to be an expert in the field to really look at it and say: Why should we have a couple of hundred companies all out there essentially being duplicates of each other, trying to provide the same basic service? It doesn't make any sense." </p>
<p> He pictures maybe 20 to 30 big, efficient T&amp;D companies. </p>
<p> Yet he knows of few other "T&amp;D only" companies but GPU domestically, and his company is only halfway there. </p>
<p> Two U.S. companies that are transmission-only are Maine Electric Power and Vermont Electric Power Corp. The second company has just 534 miles of line and is owned by 16 of Vermont's 22 utilities, to which it provides a return on equity of 8 percent. </p>
<p> Looking at GPU activities throughout the corporate hierarchy, one could draw the conclusion that it could be sending mixed messages on its vision. After all, it's investing in co-generation plants in Georgia in the U.S., England, Columbia, Bolivia, Pakistan, Turkey, the Philippines and Canada. At press time, GPU also was pursuing a partnership with the Williams Cos. to sell commodity. </p>
<p> Hafer says there are explanations for both endeavors. </p>
<p> On the commodity side, he says, the company still sees a place for itself with small and medium-size customers, particularly commercial customers. </p>
<p> "So when I talk about not wanting to be in the commodities business, I agree, I'm not being totally honest," he says. "I say it in the sense I think of that in terms of bulk power trading and the generation game. I think that is a business that's going to be characterized by a relatively few, very large players. I believe that there's a second level, however, for regional players. And that is at this retail, small and medium-size customers." </p>
<p> Co-gen, Hafer admits, is a remnant of the past, but it still fits into overall strategy. </p>
<p> "In those areas where the generation business is going to be converted from the essentially the contract business that it is today under the regulatory scheme into a commodity business, we have said we are exiting that," he says. "However, for those businesses where it is a contract generation business - that is, we have a contract with a company or a system to take the output of the plant at an established set of prices - those are businesses we will continue to be in and in fact if new opportunities present themselves, we would entertain taking on more of those projects." </p>
<p> Looking toward the future, GPU hopes to augment its telecommunications network that uses the same poles and towers covered by its 66,000-square-mile U.S. T&amp;D system. It plans on investing $10 million to extend its fiber optics in the near future. </p>
<p> It had hoped to learn more about gas distribution in Australia but Texas Utilities Co. may squash those plans. </p>
<p> GPU had received a 10-percent interest in Allgas Energy Limited, a natural gas distribution company in Brisbane, when it sold its 50 percent interest in Solaris Power, an electric distribution company. The Solaris sale was required by the state of Victoria so GPU could buy PowerNet. Cross-ownership in the electric industry is prohibited in Victoria. </p>
<p> But GPU's future in Allgas is uncertain. At press time, TU had topped competitive bidder Boral Ltd. to buy the gas distribution company. If TU is successful, GPU plans to sell its stake and write the company off as a learning experience, says Dennard, the GPU spokesman. </p>
<p> Hafer is confident that more services and business opportunities will unfold with the market. </p>
<p> "I have a feeling there may be products and services just over the horizon, but out of sight, that will come into being and turn out to be profitable and worthy of pursuit, just as in the telecommunications business; once pieces of that were deregulated and competition was introduced all kinds of creative things started to happen," he says. "At GPU, we have formed a company to be able to take advantage of those developments, but we have been very disciplined in our approach to avoid spending money when there isn't any obvious business plan or payback. </p>
<p> "So I think there is a business out there somewhere," he says. "I think it may become a lot clearer as deregulation progresses and as creativity begins to kick in, as it always does when the profit motive is introduced." </p>
<p> Joseph F. Schuler Jr. is senior associate editor at Public Utilities Fortnightly. </p>
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Mon, 15 Jun 1998 04:00:00 +0000puradmin9815 at https://www.fortnightly.comThe Cost of Reducing SO2 (It?s Higher Than You Think)https://www.fortnightly.com/fortnightly/1998/05-0/cost-reducing-so2-its-higher-you-think
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Anne E. Smith, Jeremy Platt, and A. Denny Ellerman</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - May 15 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> LAST YEAR, IN JUSTIFYING THE PROPOSED NEW NATIONAL AMBIENT Air Quality Standards (NAAQS) for particulate matter and ozone, Environmental Protection Agency Administrator Carol Browner testified that: "During the 1990 debates on the Clean Air Act's acid rain program, industry initially projected the costs of an emission allowance¼ to be approximately $1,500¼ Today those allowances are selling for less than $100." %n1%n </p>
<p> Later in 1997, at the White House briefing announcing President Clinton's Global Climate Change Plan, Katie McGinty, chairwoman of the Council on Environmental Quality, said of the plan to reduce greenhouse gas emissions in the U.S.: "We've reduced the emissions that cause acid rain by more than 40 percent of what was required¼ for less than a tenth of the price that was predicted¼ We will put [the same] market forces to work to help us take on this [climate change] objective." %n2%n </p>
<p> Statements like these attempt to justify some of the most ambitious air quality initiatives ever considered. However, the initial cost projections never ran as high as those cited today by the White House or the EPA. Initial cost estimates for achieving the sulfur-dioxide emissions reductions envisioned under the fully implemented Phase II cap in the acid rain provisions of Title IV of the Clean Air Act ranged much lower (em from $225 to $500 per ton. Further, costs were projected even lower during the period preceding the date of full compliance with the Phase II cap, and we are still in that period. </p>
<p> These discrepancies stem from inappropriate comparisons. It is no longer possible with market-based regulations to directly compare costs just because they are all expressed in "dollars per ton." It is now essential to understand whether a cost is an average or a marginal cost, short-run or long-run, a capital investment, current expenditure or a market price, or even ex ante or ex post. Sound confusing? It is. The quotes above are evidence of just how far off-base policy prescriptions can go if one doesn't take care to avoid comparing numerical values that are like apples and oranges. </p>
<p> Title IV capped annual emissions at 9 million tons, to be achieved in two phases. Phase I began in 1995, and required only 110 power plants with 263 generating units to balance their emissions with allowances. About 182 additional units opted in. Phase II will begin in the year 2000, when essentially all major fossil units must obtain allowances to operate; only about 9 million allowances will be distributed each year. </p>
<p> Utilities were given the option in Phase I of "banking" unused allowances. Allowances not used in Phase I could be banked for use in Phase II, smoothing the transition to the ultimate cap of 9 million tons. </p>
<p> Banking strategies encouraged early compliance with emissions reductions targets, whereby the units covered by Phase I reduced emissions more than required. This overcompliance is what the CEQ's McGinty was referring to when she cited reductions of 40 percent more than what was required by law. However, that 40-percent overcompliance reflects only the early years of a multi-year phase-in (see Figure 1). </p>
<p> Starting in 2000, the beginning of Phase II will usher in a lower cap, marking the start of an era of "late compliance," as plant owners draw down the bank, allowing them to delay the full force of the Phase II cap. Current estimates say the bank will supplement compliance strategies until sometime between 2005 and 2012, depending on a variety of factors. %n3%n </p>
<p> Most of the historical cost estimates alluded to here apply to a fully implemented SO2 cap with no remaining bank. They do not necessarily show what Title IV may have cost to date. However, the experience gleaned from the allowance market during the past several years can prove useful in analyzing the actual costs of Title IV. </p>
<p> Today, the average cost actually experienced in Phase I is about $200 per ton. This figure falls within the range of the initial projections for Phase I. Today's most up-to-date estimates for Phase II average costs run about $185 to $220 per ton. This interval lies at the low end of the initial range of estimates for Phase II. Actual allowances trade much lower, but we will show that current prices nevertheless remain consistent with actual average costs of about $200 per ton. </p>
<p> Early Forecasts: Accounting for </p>
<p> Flexibility in Control Measures </p>
<p> The current lore is that initial cost estimates for Title IV exceeded $1,000 per ton. This perception appears to have been falsely created by confusion regarding the distinction between marginal and average costs (see sidebar, "Program Terminology"). </p>
<p> Estimates in the range of $1,000 per ton or more have always been for the marginal costs, i.e., costs associated with the most difficult-to-control sources. That narrow focus overlooks the flexibility made possible through emissions trading. </p>
<p> For example, a paper from as long ago as 1985 clearly shows that control costs would exceed $1,000 per ton only for scrubbing of units that are already using lower sulfur fuels. %n4%n Barring emissions trading, many units had been estimated to face such high costs, yet it was readily acknowledged that a well-functioning allowance market would reach equilibrium at far less cost because the few units at the high-cost end of the range would have the flexibility to purchase allowances from lower-cost sources, who in turn would control more than would be required under the less flexible regulation. </p>
<p> Many of the proposals for legislation prior to 1987 did not envision much flexibility regarding what control measures might be selected by individual sources. Some of the proposals would have entailed widespread use of flue-gas desulfurization (FGD), which can be very costly for some power units. By the late 1980s, the idea of emissions trading had started to emerge from academic discussions as a political reality and proposals for legislation of SO2 became increasingly flexible in terms of implementation. </p>
<p> As flexibility became an increasingly important feature of regulatory proposals, it was viewed as less and less likely that any units might be forced into these more costly measures. In fact, when the Title IV legislation was being written, $1,500 per ton was viewed as such an unlikely cost that it became the price set for a reserve supply of allowances that the government guaranteed to make available to new companies as a last resort in the event of hoarding. The punitive charge associated with failure to comply was set at $2,000 per ton, "several times more than the estimated average cost per ton of reducing SO2 emissions." %n5%n This penalty was selected because it was viewed as being so much higher than any expected costs of obtaining allowances that it would serve as a deterrent to non-compliance. </p>
<p> Policymakers generally rely on total annual cost to measure total control costs. They may also refer to average annual cost, particularly where there are variations in estimates of the total tons reduced. Table 1 lists a number of such cost estimates for Title IV, starting at the time that its final form was emerging in legislative bills in 1989. The estimates from the original studies have all been converted to a common year (1995 constant dollars). Since the cap is different for Phase I and Phase II, the costs will be different between the two time periods and are shown separately. The estimates for Phase II are all for the year 2010, by which time the bank can reasonably be expected to have been used up. Thus, 2010 marks the first period in the different studies that exhibits a comparable degree of stringency and therefore comparable cost estimates. </p>
<p> Table 1 shows that, even after inflating early cost estimates to 1995 dollars, the estimates for average cost per ton generally vary in a range of $150 to $300 per ton for Phase I and $225 to $500 per ton for full implementation in Phase II. TBS noted that its cost estimates would be 20 to 25 percent lower if emissions trading were included in the estimate. %n6%n This adjustment is shown in the table. All other estimates in Table 1 did incorporate fully flexible emissions trading. </p>
<p> Table 1 also provides estimates of marginal costs, which, though not particularly useful for understanding a program's total control costs, are nevertheless useful for forecasting allowance prices. (With the advent of trading, they have often been the values cited in trade press summaries of new studies.) Analyses by EPRI have focused almost entirely on marginal costs. Estimates of all three cost indicators are presented in the same table to help eliminate confusions from the past. </p>
<p> Phase I Costs: </p>
<p> Recognizing Realities in Fuel Markets </p>
<p> Table 1 shows how the pre-implementation estimates for Phase I ranged from about $150 to $300 in terms of average cost per ton. Yet, anyone who has given passing attention to the press is likely to be aware that allowance prices have always appeared lower than expected, with a particularly notable drop to approximately $70 per ton in March 1996. Why the discrepancy? Had Title IV actually incurred lower control costs than estimated? </p>
<p> The most recent in-depth assessment of actual costs incurred for Phase I comes from the Massachusetts Institute of Technology, in work funded by the National Acid Precipitation Assessment Program. Their results are shown in Table 2. </p>
<p> MIT researchers find that the actual total costs of SO2 control measures in Phase I were $0.7 billion per year in 1995, for a reduction of 3.5 to 3.9 million tons of SO2 relative to what would have occurred without Title IV. Thus, the actual long-run average costs of Phase I appear to be about $187-210 per ton. </p>
<p> MIT's analysis indicates there have been errors in expectations during the market start-up that have raised costs above the minimum achievable. A key cause appears to have been inability to anticipate economic displacement of midwestern high-sulfur coal by western low-sulfur coal, combined with the fact that many of the control decisions involved irreversible capital investments with 3- to 4-year lead times, or fuel contract rigidities. Scrubber-related bonuses and outright political pressure to use flue-gas desulfurization added to the market-information gaps to bias compliance strategies towards FGD. The result was aggregate "overcompliance" with the cap was greater than had been expected when companies were first making their decisions on (and financial commitments to) compliance strategies. </p>
<p> At the same time, costs have fallen for individual control measures. For example, FGD now appears to cost about half what it cost in 1990. %n7%n Low-sulfur coals are also substantially cheaper, particularly delivered to parts of the Midwest that have access to coals from Wyoming (Powder River Basin, or "PRB" coal), made cheaper due to railroad productivity improvements and heightened competition that has occurred since the mid-1980s. However, the flexibility built into Title IV allowed owners to take advantage of the suddenly cheaper low-sulfur coals as a compliance option, increasing incentives for FGD manufacturers to reduce costs to retain what they could of their expected market. Further, the flexibility of Title IV increased the number of ways in which technology costs could be reduced: FGD could now be installed without costly backup systems that would have been essential if 95-percent control levels were mandated. Instead, a much less costly version of FGD has been made possible (e.g., single large vessels), where any failures of the control equipment could be paid for via additional allowance consumption rather than insured against through more costly capital investment. </p>
<p> Rethinking Phase II: </p>
<p> What Demand for Coal Generation? </p>
<p> How much do we now think Title IV ultimately will cost in light of new information about load growth patterns, market performance, and technological improvement? </p>
<p> The ultimate costs of Phase II are still unknown, but </p>
<p> pre-implementation estimates ranged between $1.5 billion to $6.5 billion per year, with average costs between $225 and $500 per ton (Table 1). The lower ends of the ranges were associated with lower levels of coal-fired generation. Using these assumptions, the lower end of the range was $225 to $350 per ton. </p>
<p> Because of the unexpectedly large allowance bank (whose final size is uncertain), full implementation of Phase II remains almost as far in the future as it was at the time that original Title IV cost estimates were being made. That is, in 1990, Phase II was expected to be fully implemented by about 2002, or about 12 years in the future. Eight years later, we find full implementation of the Phase II cap still to be about nine to 12 years away. Thus, forecasts of the ultimate total costs of Title IV remain a long-run projection (em not something that anyone can state with confidence even today. </p>
<p> Overall the range has narrowed among the most up-to-date estimates of ultimate costs for Phase II. This narrowing can be illustrated by work at EPRI and Resources for the Future. However, the range still overlaps with the low end of earlier estimates. </p>
<p> EPRI's updated estimates of total Title IV costs factor in lower FGD, lower sulfur coal prices and a range of uncertainties (see Table 2). As with pre-implementation estimates, the key uncertainty comes from load growth (em or, more specifically, the demand for coal-fired generation, which are shown in separate rows in the table. Looking into the future, arguments can be made for either higher or lower levels of fossil plant use. Higher growth could stem from higher economic growth generally, and from electrification, as well as possibly from lower prices from deregulation. Lower demand growth could develop from conservation and end-use efficiencies. Furthermore, future regulatory initiatives, such as controls for particulates or carbon dioxide, could dramatically alter demand for coal-fired generation. That prospect supplies the primary impetus for EPRI's "low-demand" scenario (bottom row, Table 2). </p>
<p> The middle row of Table 2 shows EPRI's long-run average and marginal cost estimates using an updated base-case demand for coal-fired generation. The base-case range depends mainly on whether control investments are amortized over 10 or 20 years. With lower assumptions for coal plant utilization (which EPRI does not consider a likely outcome unless there are significant new regulatory initiatives), the marginal costs could be as low as $275 per ton. These estimates take into account all of the various cost reductions that have been observed, including lower costs for low-sulfur coals and reduced costs for FGD, reflecting reduced backup requirements and cheaper technology. </p>
<p> EPRI's best judgment of the additional cost to achieve Phase II is $0.8 billion to $1.4 billion per year. (If coal-fired generation demand growth rates were reduced by half, that figure would drop to $0.4 billion per year.) Adding these estimates to the $0.7 billion per year cost to achieve Phase I, EPRI now figures the total cost for Title IV compliance will be $1.5 billion to $2.1 billion per year (or as low as $1.1 billion per year with lower coal plant use, which EPRI does not consider a likely outcome). </p>
<p> Researchers affiliated with Resources for the Future are developing an econometric model of SO2 reduction costs that differs from the engineering approach seen in all the studies cited in Tables 1 and 2, particularly in that it estimates endogenous rates of change in cost parameters and demand. The RFF model is particularly interesting because it fairly closely reproduces the early engineering cost estimates of Table 1 when applied using the assumptions about demand, prices, and technologies that were accepted around the time of those studies. It also tracks fairly closely the actual costs of Phase I when actual compliance actions are applied. At the same time, the model suggests that $0.2 billion to $0.3 billion per year of the actual costs in Phase I could be avoided (while still meeting the actual 1995 emissions levels) by further optimizing fuel choices. If so, this work suggests that possibly as much as 25 percent of the actual Phase I costs already incurred may not be permanently fixed, leaving room for some further downward revisions in the updated cost estimates discussed above. Although their work is still in progress, RFF researchers offer their own "best judgment" of $1.3 to $1.4 billion per year for total costs of Title IV SO2 reductions. </p>
<p> Current Allowance Prices: </p>
<p> Depressed by Excess Capacity </p>
<p> In contrast to control measure costs, allowance prices have proved much lower than expected. In a well-functioning market, allowance prices would roughly coincide with long-run marginal costs. Yet, while marginal costs for Phase I sometimes exceeded $500 per ton, allowance prices have remained around $100 per ton. How can these lower-than-anticipated allowance prices be explained? </p>
<p> One possible answer is unintended overinvestment in compliance. This resulted from the challenge that individual companies faced prior to Phase I in estimating full-market control costs in conditions of uncertainty to devise their control strategies, cognizant of both immediate and coming requirements. </p>
<p> For example, if participants overestimate marginal costs, they may invest too heavily in control measures, creating more allowances for sale than are needed to achieve the cap in any given year. Allowance prices fall. Moreover, because SO2 control measures exhibit a large degree of "irreversibility," such excess supply conditions can well persist. Thus, one benchmark for how low allowance prices might fall before companies stop creating more of them lies in the short-run cost of running a scrubber. That cost reflects daily operating costs, such as reagent, power consumption and labor, but not those associated with recovering capital investment. In fact, for many potential sellers of allowances, the cost of continuing to generate excess allowances is zero. </p>
<p> Consider companies that achieved compliance earlier than Phase I because of increasingly lower costs of delivering western low-sulfur coal to mid-western power plants (due to falling rail rates), or because of the need to comply with more stringent state regulations. For these sellers, the price question is not what the allowances cost, but what they are worth to others, or to themselves for future internal use. </p>
<p> In 1995, it became apparent that overcompliance had been substantial: emissions of the 445 units affected by Phase I of Title IV totaled only 5.3 million tons of SO2 relative to a cap in 1995 of 8.7 million tons. %n8%n The actual amount of banking, 3.4 million tons, exceeded earlier estimates by as much as 1.5 million tons. (The number will decline by about 1 million tons in 1997 due to the drop in bonus allowances awarded for the first two years of scrubbing.) The fact that the excess allowances could be saved for a future day when the cap will be more binding is what gives these allowances financial value. </p>
<p> A second consideration is the ability to bank allowances for future years, which strongly influences today's allowance trading prices. In fact, if Phase II control costs turn out to be high enough, Phase I excess controls may yet generate a return despite the low current price for allowances. How high must prices rise to make banking a profitable strategy? If we take an average price in 1996 of about $100 per ton, and assume that the average real rate of return of utilities is 8 percent, then the 1996 price appears consistent with expected allowance prices in 2008 to 2010 of $233 to $272 per ton (in constant dollars). With equally plausible, higher discount rates, today's low prices appear consistent with even higher future marginal costs. This sort of comparison should not be overdone, however; it compounds uncertainties (coal generation levels, choices of discount rates, many cost assumptions and other regulatory and business risks not explicitly accounted for). </p>
<p> Thus, today's allowance prices do tell us something, but it isn't what total control costs have been so far. First, they indicate the present value of today's expectation of future compliance costs, using a rate that embodies a probably substantial risk premium for future regulatory changes. Second, the current allowance price offers a picture of today's short-run marginal costs. </p>
<p> In the short-run, the considerable FGD capacity now installed creates an effective floor to allowance prices at FGD's operating cost of about $50 to $65 per ton. %n9%n This cost appears consistent with the very lowest allowance price experienced of about $70 per ton. Today's higher allowance prices are thus consistent with the short-run cost of switching to low-sulfur coal, which is based on the price premium for coals with lower-sulfur contents, and is $100 to $120 per ton of SO2 reduced. Thus, the current short-run marginal cost of switching is the current cost most related to today's allowance price. </p>
<p> Future Price Trends: </p>
<p> Dependent on Ozone, Particulates and CO2? </p>
<p> What might happen to future allowance prices if additional control costs were imposed through new regulations for ozone, particulate matter or carbon dioxide? Answer: It all depends on how the new regulations might be implemented. </p>
<p> PARTICULATES. The new NAAQS for fine particles (particulates less than 2.5 microns, or PM2.5) is one regulatory change that substantially affects expectations of the SO2 allowance market. (A standard for particulates would target SO2 emissions, which contribute to fine particle formation.) </p>
<p> EPRI has estimated this new target would increase projected control costs by $3 billion to $5 billion per year greater than those of Phase II. It finds marginal costs could be as high as $1,350 per ton, %n10%n and the benefits of emissions trading relative to a straight technological requirement are reduced. </p>
<p> In the SO2 market, if the Title IV cap-and-trade program was retained and allowance allocations were cut in half through new legislation, then allowance prices would increase substantially. The stricter cap would greatly reduce the range of options, since the sulfur content of coal simply does not go low enough. If, however, any additional SO2 reductions were to come from local requirements laid on top of the present Title IV cap (as might be expected for regulations directed at ambient air quality), then this greater stringency would render the Title IV cap meaningless. The new NAAQS requirements would create a flood of allowances and would shrink the pool of potential buyers. Although allowance prices would plummet, costs to reduce SO2 would increase. Current allowance prices (which depend in part on future prices) would also fall. </p>
<p> CARBON DIOXIDE. Though less imminent, any cap imposed on carbon-dioxide emissions to address climate change would also likely affect SO2 allowance prices. The primary way to achieve CO2 cuts is to replace coal and oil with natural gas or renewable fuels or to improve energy efficiency. Both methods will reduce demand for coal-fired power and cause the baseline of SO2 emissions (and the demand for allowances) to drop. Overall, this result would dampen the growth in allowance prices but these lower prices would not be attributable to the benefits of allowance trading. </p>
<p> TRADING PROGRAMS. What if new NAAQS requirements were imposed through an entirely new emissions trading market, such as allowances for NOx or for CO2? Many lessons might be drawn from SO2 trading. </p>
<p> One key feature of the SO2 market would need to be present again. The SO2 cap was set at a level that left a wide range of options open to each individual source: an approximate 50-percent reduction was required in a situation where there was a technologically proven option that could achieve reductions of 95 percent. Combined with that was the presence of a wide continuum of lower percentage reductions possible via fuels with many different sulfur content levels. Thus, there was room for applying the most costly control measures on only a small fraction of the regulated units, where they would be truly cost-effective. This situation also laid the groundwork for substantial price competition among very different types of control options. A more stringent cap would have reduced the degree of flexibility to manage costs, and probably also the degree of price competition among suppliers of control options. The ability to take advantage of cheaper low-sulfur coals from the West would have been greatly diminished if aggregate SO2 reduction requirements were substantially greater than 50 percent. </p>
<p> Market-based regulatory approaches are here to stay. Emissions trading has proven an effective tool, but will not make the cost of controlling emissions disappear. It is not fair to say that the Title IV experience shows that initial cost estimates are not to be trusted for guiding policy decisions. As always, the main determinant of cost is the stringency of the measure. F </p>
<p> Anne E. Smith is vice president with Charles River Associates. Jeremy Platt is manager, fuel supply target, EPRI. A. Denny Ellerman is executive director of the Center for Energy and Environmental Policy Research, MIT. The authors drew on data and analyses performed independently at MIT and EPRI to provide an updated perspective on Title IV's costs and to contrast these current data appropriately with initial cost estimates. </p>
<p> Program Terminology </p>
<p> Benchmarks for Cost Comparisons </p>
<p> TOTAL CONTROL COST: Sum of control costs (both capital and operating) for all individual sources covered in program. Often stated in terms of total annual costs, to reflect actual expenditure flows. (Note: All definitions listed exclude ancillary costs such as government administration and monitoring.) </p>
<p> AVERAGE COST: Total control cost (see above) divided by estimated tons of emissions reduced, allows comparability by policymakers for programs with different control objectives. Often confused with marginal cost (below), since each is expressed in dollars per ton. </p>
<p> MARGINAL COST: The highest per-ton cost incurred by any individual source or source category included in calculating average cost (see above). Always equals or exceeds average cost. Difference between marginal and average cost can vary significantly between programs. Often considered a good predictor of long-run allowance prices for market-based emissions programs. </p>
<p> ALLOWANCE PRICE: The cost of buying an allowance. Also represents price received for selling an allowance created and earned by undertaking physical control measures, but does not necessarily represent the cost incurred thereby. </p>
<p> LONG-RUN COSTS: Includes cost of building or installing a control measure (the capital cost). Capital costs are always included in regulatory cost projections, and for the most part, both average and marginal cost projections represent long-run estimates. </p>
<p> SHORT-RUN COSTS: The cost of operating the control equipment. Is most relevant for explaining disequilibrium market price behavior. Short-run costs, and hence midterm market outcomes, may vary significantly from the actual total costs of the control program, though each is expressed in dollars per ton. </p>
<p> TIME FRAME: Is the cost estimate of a Phase I cost, an early Phase II cost, or a later, "fully implemented" Phase II cost? </p>
<p> 1 Before the Committee on Environment and Public Works, U.S. Senate, Feb. 12, 1997. </p>
<p> 2 Washington D.C., Oct. 22, 1997. </p>
<p> 3 EPRI, SO2 Compliance and Allowance Trading: Developments and Outlook, prepared by K. D. White, Palo Alto, California, April 1997; tr-107897 4129; p. 1-12. </p>
<p> 4 Crocker T. D.; J. L. Regens. "Acid Ceposition Control," Env. Sci. &amp; Tech., 1985. 19(2). pp. 112-116; (Table 2). </p>
<p> 5 U. S. General Accounting Office. Allowance Trading Offers an Opportunity to Reduce Emissions at Less Cost, Washington, D.C., December 1994; gao/rced-95-30; p 18. </p>
<p> 6 Temple, Barker &amp; Sloane, Incorporated, Economic Evaluation of H.R.3030/S.1490 "Clean Air Act Amendments of 1989": Title V, The Acid Rain Control Program, slides prepared for the Edison Electric Institute, Aug. 30, 1989, p. 4. </p>
<p> 7 Ellerman A. D.; Schmalensee R.; et al., Emissions Trading Under the U.S. Acid Rain Program: Evaluation of Compliance Costs and Allowance Market Performance, MIT Center for Energy and Environmental Policy Research, Massachusetts Institute of Technology: Cambridge, Massachusetts, 1997; mit e40-279, p 43. </p>
<p> 8 Ellerman A. D.; Schmalensee R.; et al., op. cit. p 15. </p>
<p> 9 Ibid, Table 8 and p 49. </p>
<p> 10 EPRI, The New Environmental Drivers: Challenges to Fossil Generation Planning and Investment, prepared by K. D. White, Palo Alto, Calif., March 1998 (in press), epri tr-110261, p. 4-23. </p>
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Fri, 15 May 1998 04:00:00 +0000puradmin9788 at https://www.fortnightly.comNews Digesthttps://www.fortnightly.com/fortnightly/1998/04/news-digest
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Lori A. Burkhart, Phillip S. Cross, and Beth Lewis</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - April 1 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> Federal Agencies </p>
<p> ELECTRIC RETAIL PRICES. The Energy Information Administration has released a new report finding that the average retail price of electricity has declined for the third year in a row and remained stable for the first nine months of 1997. According to Electric Sales and Revenue 1996, average residential electric prices declined slightly in 1996, the first drop for that consumer class since the EIA began collecting data in 1984. Overall average prices of electricity were down nearly 0.5 percent nationwide between the end of 1996 and 1997, while industrial prices were down more than 1 percent. In California, residential prices dropped by 2.4 percent in 1996. The EIA believes three reasons account for the lower prices: falling fuel prices; decreasing labor costs; and lower interest rates on money borrowed. The report is available online at <a href="http://www.eia.doe.gov">www.eia.doe.gov</a>. </p>
<p> LONG-DISTANCE REVENUE. The Federal Communications Commission released a staff report, Long Distance Market Shares, which shows that as of the third quarter of 1997, 83 percent of long-distance revenues went to the four largest long distance carriers: AT&amp;T, MCI, Sprint and WorldCom. The report can be downloaded from the FCC-State Link Internet site at <a href="http://www.fcc.gov/ccb/stats">www.fcc.gov/ccb/stats</a>. </p>
<p> NUCLEAR WATCH LIST. The Nuclear Regulatory Commission has released its revised watch list of 13 nuclear power plants that warrant increased attention. Illinois Power Co.'s Clinton plant was the only plant added to the list; Maine Yankee Atomic Power Co.'s plant, which is being shut down, was the only plant removed from the list. </p>
<p> NUCLEAR WASTE DISPOSAL. As expected, the Department of Energy did not meet its Jan. 31 deadline to begin storage of high-level nuclear waste, as required by a federal court. Under the Nuclear Waste Policy Act of 1982, a permanent waste repository was to have been completed by 1998. But DOE has said that the likely repository at Yucca Mountain, Nevada, will not be ready until 2015 at the earliest. Electric ratepayers so far have paid about $14 billion into the Nuclear Waste Fund. Because the federal government now has defaulted on the deadline, DOE ultimately could be liable for as much as $56 billion in damages, and as much as $24 billion more for replacement power costs. Senator Frank H. Murkowski blasted DOE's failure to meet the deadline: "It's blatantly hypocritical and intellectually dishonest for the Administration to complain about carbon emissions and global warming while¼ putting our largest source of carbon-free energy at risk." </p>
<p> Environmental Issues </p>
<p> NITROGEN OXIDE EMISSIONS (em AUCTIONS. ISO New England will conduct the first multi-state auction of nitrogen-oxide emission reduction credits. ISO-NE members will purchase the credits to offset increases in NOx emissions generated last summer. The rise in emissions stemmed from the operation of certain power plants to avoid electricity capacity shortfalls in New England. The credits will apply to the "ozone season," May through September, and can come from anywhere in New England. </p>
<p> NITROGEN-OXIDE EMISSIONS (em EPA REVIEW. Many concerns were raised at a recent hearing over nitrogen-oxide state implementation plans proposed by the Environmental Protection Agency. Mark Gray, manager of Environmental Services for American Electric Power, said Feb. 3, that the EPA disregarded recommendations of the 37-state Ozone Transport Assessment Group. The group had suggested a range of emission reductions (em from 55 percent to 85 percent (em instead of an "onerous one-size-fits-all" approach. </p>
<p> Utilities, labor groups, and other organizations from the regions that the plan would affect have formed the Alliance for Constructive Air Policy, a coalition that will work with policymakers to find methods to reduce ozone pollution. ACAP members are developing an alternative proposal to EPA's proposal. </p>
<p> The EPA's plan, proposed in November 1997, would require uniform NOx emissions reductions of 85 percent by utilities and other large sources in 22 states in the Midwest, Mid-Atlantic, Southeast and Great Lakes regions. </p>
<p> FERC </p>
<p> GAS PRODUCER REFUNDS. The FERC on Jan. 28 again ruled that natural gas producers must refund to customers approximately $500 million for gas produced in Kansas and sold interstate at rates that included Kansas ad valorem or property taxes. In denying rehearing, the FERC noted that such taxes are not eligible for inclusion in rates under the Natural Gas Policy Act of 1978. Last fall the FERC had ruled that a court ruling left it no choice but to order the refunds. Amoco Production Co., Anadarko Petroleum Corp., Mobil Oil Corp., OXY USA Inc., and Union Pacific Resources must refund the money by mid-March, which the companies claim will produce financial hardship. Legislation introduced in both the U.S. Senate and House of Representatives would require the producers to pay only the principle owed (em not the interest, which makes up nearly 80 percent of the $500 million. Docket Nos. rp97-369-001 et al., Jan. 28, 1998 (F.E.R.C.). </p>
<p> PIPELINE RATEMAKING. While it has issued a certificate to Transcontinental Gas Pipe Line Corp. for construction and operation of its Mobile Bay, Ala., offshore lateral, the FERC nevertheless has denied rehearing of a prior order that approved rolled-in rates instead of incremental pricing. Docket Nos. cp97-92-000, et al., Jan. 28, 1998 (F.E.R.C.). </p>
<p> Transco had argued that it qualified for a presumption of rolled-in rate treatment under the commission's statement of policy on pipeline pricing. See, 71 FERC ¶ 61,241 (1995), order on reh'g., 75 FERC ¶ 61,105 (1996). </p>
<p> Courts </p>
<p> STRANDED COSTS. The New Mexico Supreme Court examined whether state law gives the city of Las Cruces authority to condemn facilities owned by El Paso Electric Co. This issue had been certified to the state Supreme Court by Judge Leslie Smith of the U.S. District Court and the issue has been returned to Judge Smith's court for a final determination. City of Las Cruces v. El Paso Electric Co. et al., No. 23,846, Feb. 10, 1998 (N.M.) </p>
<p> Meanwhile, the Federal Energy Regulatory Commission on Feb. 12 held a hearing to determine how much, if any, stranded costs the city would owe El Paso Electric if it takes over the electric system. Docket No. sc-97-2-000 (F.E.R.C.). </p>
<p> PURCHASED POWER CONTRACTS. The owners of two waste-to-energy generating plants filed a $1.8-billion lawsuit in Palm Beach County Circuit Court against Florida Power &amp; Light Co., alleging contract violations in a dispute related to Florida's largest municipal bond default. The now-shut-down plants are owned by Okeelanta Power and Osceola Power Ltd. Partnership, which are affiliates of PG&amp;E Corp., Bechtel Enterprises, and Flo-Sun Inc. Florida Power &amp; Light entered a contract to purchase the output, but then argued it had no further obligation to continue the purchases because operating deadlines were not met. The owners counter-sued the utility for the $1.8 billion it contracted to pay over 30 years. </p>
<p> TELECOMMUNICATIONS RETREAT. Texas U.S. District Judge Joe Kendall issued a temporary stay of his Dec. 31 ruling striking down key parts of the Telecommunications Act of 1996, pending an appeal by the Federal Communications Commission and long-distance companies. Kendall had found that the Act inflicted serious financial punishment on Bell System operating companies by keeping them out of the long- </p>
<p> distance business. SBC Communications, Inc. v. FCC, No. CIV.A. 7:97-cv-163-x, Dec. 31, 1997 (N.D.Tex.). </p>
<p> WATER PLANT RATE BASE. A Florida appeals court has struck down a state PSC ruling for arbitrarily changing a rate-base method for a wastewater treatment plant. It faulted the PSC for comparing plant capacity against annual average daily flow in place of using the peak-month average daily flow. Florida Cities Water Co. v. Fla. PSC, No. 96-3812, Jan. 12, 1998 1998 WL 5407 (Fla.App.). </p>
<p> State PUCs </p>
<p> LOCAL TELCO COMPETITION. The North Carolina Utilities Com- </p>
<p> mission has turned down a request by Time Warner Communications of North Carolina to offer competitive local exchange telephone service within the service territory of an established local exchange carrier, ALLTEL Carolina Inc., deciding that ALLTEL did not lose an exemption protecting its franchise territory from competition simply because one of its affiliates, ALLTEL Communications, had received certification as a competitive local carrier. (Under the state's telephone reform law, LEC franchise territories with less than 200,000 access lines are exempt from competition if the incumbent carrier does not compete outside its area or elect price regulation.) Docket No. p-472, Sub 6, Jan 7, 1998 (N.C.U.C.). </p>
<p> LOCAL TELCO RATES. The New Jersey Board of Public Utilities </p>
<p> approved a schedule of rates for local exchange services to be offered by MFS Intelenet of New Jersey Inc., a new entrant in the state's local telephone market. In doing so it ruled that a detailed cost review was not justified because the new carrier has no captive customers, and any customers it might attract can easily obtain local service from Bell Atlantic-New Jersey Inc., the incumbent carrier. The board added that the proposed rates could not be considered unreasonable considering the "competitive posture" of the new carrier, and the "procompetitive policies of both federal and state law." Docket No. tt97010043, Jan. 7, 1998 (N.J.B.P.U.). </p>
<p> NEED FOR POWER. The Alabama Public Service Commis- </p>
<p> sion authorized Alabama Power Co. to build an 800-megawatt, combined-cycle generating unit at its existing Barry Steam Plant facility. The PSC rejected claims by independent power producers that the utility had failed adequately to consider whether retail competition would mitigate its need for power. The commission said that the utility must clearly have additional capacity by 2001 to maintain reliable service and that the form and extent of changes in the state's electric industry structure were not yet certain. It also rejected claims by the IPPs that the company's plan was flawed because the need for power could be satisfied at a lower cost through the construction of combustion turbine units by competitive suppliers. It said that such an analysis failed to consider the need to minimize the "total cost" of generation by balancing the amounts of peaking, intermediate and baseload capacity. Docket No. 26115, Dec. 12, 1997 (Ala.P.S.C.). </p>
<p> TELCO/CABLE CROSS-SUBSIDY. The Michigan Public Service Commission directed Ameritech Michigan, a local exchange carrier, to stop participating in a marketing program with an affiliated cable television company, Ameritech New Media Inc. Other cable providers in the state had complained that Ameritech violated state law by offering checks to prospective customers redeemable for telephone service as an inducement to subscribe to New Media's "Americast" cable service. The PSC ruled that the issuance of the pre-signed, pre-dated "AmeriChecks" by the LEC, while drawn on a New Media Bank account, violated state rules banning provision of regulated service "in combination with an unregulated service." It rejected claims by the LEC that the law did not apply because the promotion involved "different corporate entities" and found that the opportunity for customers to use AmeriChecks as a discount or offset against tariffed rates for regulated services "cemented the ties creating a combination of regulated and unregulated services." Case No. u-11412, Dec. 19, 1997 (Mi.P.S.C.). </p>
<p> ELECTRIC RATE RESTRUCTURING. The Arkansas Public Service </p>
<p> Commission has authorized Entergy Arkansas Inc. to restructure its rates in anticipation of competition, permitting the utility to reduce rates and increase the pace of amortization for its nuclear generating investment. It added that it "expects the utility to¼ actively promote retail electric competition in Arkansas." </p>
<p> The approved rate restructuring plan includes: (1) rate reductions of $155 million in 1998 and $62 million beginning in 1999; (2) rate design moves to eliminate interclass subsidies without rate increases; (3) rate stability until July 1, 2001; (4) ratepayer protection against rate increases associated with loss of wholesale load; and (5) the capture of excess annual earnings and the earmarking of such funds for payment of potential future ratepayer liability for stranded costs. Docket No. 31, Dec. 12, 1997 (Ark.P.S.C.). </p>
<p> CUSTOMER AGGREGATION. Enron Energy Services has filed </p>
<p> a complaint with the state Ohio PUC challenging as "uncompetitive" a proposed long-term aggregation contract for Ohio Edison Co. to supply several McDonald's restaurants with electricity. Ohio Edison is proposing to give McDonald's a discounted electric rate in return for becoming the exclusive supplier for 10 years. Ohio Edison, a subsidiary of FirstEnergy Corp., has filed suit in the Ohio Supreme Court challenging the PUC's aggregation plan. </p>
<p> PUBLIC POLICY PROGRAMS. The New York Public Service Commission on Feb. 2 issued an order establishing policies for the administration of its Systems Benefits Charge, which will be used to promote energy efficiency and public policy programs during the transition to competition. The order designates the New York Energy Research and Development Association as a third-party administrator for SBC funds, which will be collected by the utilities over the next three years. Case 98009/94e0952, Feb. 2, 1998 (N.Y.P.S.C.). </p>
<p> ELECTRIC RESTRUCTURING PLANS. The New York PSC has </p>
<p> approved a five-year modified rate and restructuring plan for New York State Electric and Gas Corp., which allows all customers to choose their supplier of electricity by Aug. 1, 1999, and provides for overall customer savings of $725 million. Chairman John F. O'Mara noted that the plan implements "one of the most aggressive timetables for customer choice." Rates for large industrial customers and high load-factor customers will be reduced by 5 percent annually. Residential and small commercial customer rates will be frozen at present levels for the first four years of the plan, with a 5 percent reduction taking effect in the fifth year. Case 98005/96e0891, Jan. 27, 1998 (N.Y.P.S.C.). </p>
<p> RETAIL CHOICE. Following approval from the New York PSC, </p>
<p> Consolidated Edison Co. of New York Inc. on Feb. 3 revealed details of its retail choice program, to begin June 1 for about 63,000 customers. At that time, 500 megawatts of electricity will become subject to retail competition, with choice phased-in for all customers by year-end 2001. Each customer who chooses a supplier other than ConEdison will receive two bills: one for delivery of the electricity from ConEdison, and the other for the commodity sold by energy service companies. Starting in February, ConEdison bills will contain a "retail choice shopping credit," which will show how much customers can save if they purchase electricity from another supplier. The utility will pay a one-time, $50 incentive to residential and religious rate class customers, and $75 to small nonresidential customers to encourage participation in retail choice programs. </p>
<p> Mergers &amp; Acquisitions </p>
<p> RATEPAYER BENEFITS. The New Jersey Board of Public Utili- </p>
<p> ties approved the merger of Atlantic City Electric Co., and Delmarva Power and Light Co. to form a new company, Conectiv Inc. The board rejected calls for the application of stricter standards when reviewing such cases. Consumer advocates had alleged that the board should switch from a "no harm test" in reviewing merger and reorganization applications to a test that requires a showing of a "positive benefit" to ratepayers. The board said that it had used the stricter test in only two cases in recent history, and that one involved a hostile takeover bid. It went on to find that the merger would save ratepayers $15.75 million annually and that voluntary labor force reductions would limit the effects of merger-related layoffs. Docket No. em97020103, Jan. 7, 1998 (N.J.B.P.U.). </p>
<p> CANADIAN GAS SERVICES. The boards of directors of Trans- </p>
<p> Canada PipeLines Ltd. and NOVA Corp. on Jan. 26 agreed to merge the companies to create the fourth largest energy services company in North America. The new company will hold $16 billion in revenues and $21 billion in assets. NOVA shareholders will exchange each NOVA share for 0.52 TransCanada shares, and then the new company will be divided into separate energy and chemicals businesses. The companies believe that the merger will allow them to offer low-cost flexible services from the Western Canada Sedimentary Basin to end-users in North American markets. </p>
<p> Restructuring Electric Legislation </p>
<p> New bills are on deck, but many are facing rough sledding. </p>
<p> CONNECTICUT. Legislators had hoped to have a bill ready on </p>
<p> Feb. 4 and go to public hearing within two weeks from that date. The new bill closely resembles last year's failed bill. </p>
<p> INDIANA. SB 431, passed through the Senate Commerce and </p>
<p> Consumer Affairs Committee. But the electric bill is expected either not to make it to the full Senate for a vote, or to have all its key components removed. Because the state's major utilities disagree on restructuring, the legislators want to involve them in discussions to write another restructuring bill that would be considered next year. </p>
<p> NEW MEXICO. The Public Utility Commission sent draft leg- </p>
<p> islation to the legislature proposing to open the state's electric market to retail customer choice beginning Jan. 1, 2001. The PUC also submitted a report to the governor and the Legislature explaining choice from the customers' perspective by using extensive cost and socioeconomic data for all regions of the state. The draft leaves to further commission review the question of stranded cost recovery and functional separation of generation from other utility activities. Under the draft legislation, restructuring must produce stabilized or reduced rates and provide incentives for demand-side management and customer conservation efforts. Case No. 2681, Jan. 28, 1998 (N.M.P.U.C.). </p>
<p> OKLAHOMA. State Sen. Kevin Easley introduced SB 888, which </p>
<p> would have accelerated completion of restructuring studies required by the Electric Restructuring Act of 1997. But the Easley bill is stymied in committee. </p>
<p> SOUTH CAROLINA. The PSC denied a request by an electric pro- </p>
<p> vider, Electric Lite, to restructure the electric industry without legislation. It issued its own proposal for restructuring the state's electric industry, but cautioned that "there may be little to gain and much to lose" from competition. That bill will be pitted against an electric restructuring bill on the table by Rep. Doug Smith, which calls for immediate restructuring of the electric industry. The PSC recommended functional unbundling, a regional ISO and a five-year transition period for full implementation of customer choice. They would examine the need for a power exchange that allows for bilateral contracts. If permitted by the state legislature, utilities would recover "verifiable stranded costs over a reasonable period." </p>
<p> VIRGINIA. Two disparate electric restructuring bills are up for </p>
<p> consideration, one largely authored by Virginia Power. The latter does not commit to a date certain for retail choice, and the former, introduced by state Sen. Jackson Reasor Jr., would phase-in retail competition through 2004. But while Virginia Power wants its bill considered this legislative session, which ended March 14, Reasor prefers both bills be carried over to the 1999 legislative session. </p>
<p> WASHINGTON. State Sen. Lisa Brown introduced SB 6560, the Electric Consumers Protection Act, would require extensive rate disclosure and enact dispute resolution procedures. Also, when marketing power, utilities would have to identify the types of resources used to generate power, and the amount of air emissions produced. But it appears that SB 6560 likely will be killed in the House, in favor of a bill only requiring utilities to unbundle their costs of service on electric bills. </p>
<p> Business Wire </p>
<p> LOU L. PAI, Chairman and CEO of Enron Energy Services said </p>
<p> Enron plans to make "PECO-type" offers to other investor-owned utilities in the future. He promised that these offers would be made on a "more friendly basis," however. (Enron had asked the Pennsylvania PUC to allow it to become the provider of last resort to PECO's customers.) Pai predicted that Pennsylvania could become an energy hub because well-written legislation will attract businesses. The company announced plans to make major investments in the state. On the other hand, Pai pronounced that the California Independent System Operator and Power Exchange system "doesn't work¼ We see a humor in this." </p>
<p> CNG Energy Services Corp. and Cendant Corp. have agreed to jointly make available CompleteHome to CNG customers. The companies will offer CompleteHome service, one of Cendant's energy advantage programs, to more than 1.5 million CNG customers. The CompleteHome membership program offers discounts of 10 to 50 percent on the purchase of more than 100,000 name-brand home products from manufacturers such as GE, Black &amp; Decker, Sony and Maytag and home service companies such as True Value, Merry Maids, Chem Dry, Terminix and TruGreen-Chemlawn. </p>
<p> CellNet Data Systems Inc. and DukeSolutions, a subsidiary of Duke Energy, announced a contract under which CellNet will provide data communications services to DukeSolutions and Duke Energy Trading and Marketing customers over its new California network. The contract also includes an option to expand service coverage to any additional networks CellNet may build in other states. The agreement with DukeSolutions is Cellnet's fifth agreement with a major ESP to provide data communications services over its new California network. </p>
<p> News digest is compiled by Lori A. Burkhart and Phillip S. Cross, contributing legal editors, and by Beth Lewis, editorial assistant. </p>
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Wed, 01 Apr 1998 05:00:00 +0000puradmin9763 at https://www.fortnightly.comGas Price Volatility: Of Winters Past and Futures Markethttps://www.fortnightly.com/fortnightly/1998/03-0/gas-price-volatility-winters-past-and-futures-market
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Bruce W. Radford</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - March 15 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> EL NIÑO HAS STRUCK, WITH NO END IN SIGHT. </p>
<p> Consider that Aquila Energy, the marketing arm of UtiliCorp United, has announced a new financial derivative, known as GuaranteedForecast,sm to hedge the weather against forecasts by the National Weather Service. The new product will pay holders a guaranteed amount if the mercury strays, and Aquila touts its thermometer hedge for any of 170 U.S. cities (em be it Spokane, El Paso, Chicago or New York. Why talk about the weather when you can invest in it, in true '90s fashion? </p>
<p> For this heating season, however, it may be too late. </p>
<p> The American Gas Association released figures recently indicating that this year's winter so far (weeks ending Oct. 4, 1997, through Feb. 7) has been about 6.8 percent warmer than normal and 5.1 percent warmer than 1996-97. The warmer trend appeared most pronounced in January 1998, which came in nearly 20 percent warmer than normal and 18.3 percent warmer than 1996-97, according to the A.G.A. </p>
<p> Meanwhile, in the Feb. 17 issue of its Natural Gas Weekly Market Update, the U.S. Energy Information Administration said most forecasters were calling for more of the same, with implications for gas prices: "The lack of any substantial weather-related demand for natural gas so far this winter has resulted in a more than 33-percent drop in gas prices on both the spot and futures markets since mid-November." </p>
<p> Prior EIA research indicates that if average heating season temperatures rise 1.43 degrees Fahrenheit above normal, the drop in demand for natural gas will outweigh the increase that occurs each year to supply economic growth, thus forcing prices down. %n1%n In its Feb. 17 update, the EIA predicted gas storage levels "well ahead of last year," if the mild temperatures continue. </p>
<p> El Niño, it appears, has spared no one. Out west, Southern California Gas Co. lowered its procurement charge for retail core subscription to $2.0658 per MMBtu, effective Feb. 6, down from $2.3036 for January, $2.4684 in December, and $3.3872 for November 1997. </p>
<p> Nevertheless, while gas prices may be down, gas price volatility remains high. </p>
<p> On Feb. 9, for example, just a week before it was reporting that 33-percent price drop, the EIA notes an unexpected rally in gas futures prices:"[M]ost industry observers were surprised by the upward trend in both spot and March futures contract prices. The Henry Hub average spot price gained about 25 cents over the week ending Friday, Feb. 6, while the March futures contract gained almost 30 cents from the closing price on its first day of trading as the near-month contract expired on Jan. 29." %n2%n </p>
<p> John Herbert, previously on staff at the EIA and an expert on gas storage, pricing and risk management (email: <a href="mailto:jhhl@email.msn.com">jhhl@email.msn.com</a>), explains the paradox: "Gas volatility doesn't go away, despite these new markets and transparent pricing. </p>
<p> "A key factor is storage relative to demand. In general, this winter's gas market has proven to be much different than a year ago, especially at the beginning of the season. That had a lot to do with the weather, and the industry appeared to be factoring in El Niño. At the start of last winter (1996-97), storage was down, for practically all energy, including propane and oil. </p>
<p> "But at the start of this winter," explains Herbert, "propane and oil were much higher. By November, gas storage was soon found to be above the prior year's level. Storage was growing, relative to expected demand. Prices going into December and January were lower." </p>
<p> Price volatility can occur between regions as well, marked by wide fluctuations in basis (the difference in spot prices between pairs of market hubs), as explained by consultant Benjamin Schlesinger, president of Benjamin Schlesinger and Associates, of Bethesda, Md. "This past winter (1997-98), we're seeing the fairly classic pattern of western gas stuck at fairly low prices, and by that I mean the Rockies and Canada, as a result of inadequate gas transmission capacity from West to East." </p>
<p> In a recent study he published on the Internet, %n3%n Schlesinger describes the phenomenon of basis "brick walls," wherein a stark line will develop across a map of North America, dividing regions into areas of positive and negative basis, in which citygate prices lie above or below prices in the South Central producing area. He shows how a brick wall developed in April 1996 running roughly north-south along the Mississippi River valley. But that configuration had changed by December, after the brick wall evaporated and then reappeared along the U.S.-Canada border. </p>
<p> "There haven't been any basis blowouts this past winter, as we saw during the last two years. In 1996-97, for instance, we saw the "brick wall" shift and re-emerge along the northern-tier states. That reveals how you cannot predict with certainty where the next 'wall' will develop." </p>
<p> Herbert seconds the motion: "Energy tends to show greater volatility than other commodities and natural gas is about twice as volatile as other commodities, generally. And that volatility is more than just day-to-day, week-to-week or month-to-month. Volatility can be seen from year to year as well." </p>
<p> If gas price volatility is the enemy, what's the remedy? Will a solution come from more regulation to dampen price risk for consumers even though it may shut them out from potential price savings? Or, will the answer come from greater price transparency, supplied by new spot and futures markets, including even perhaps coal or electricity futures, which could allow cross-hedging between different energy inputs? </p>
<p> The Past Winter: </p>
<p> What Happened and Why </p>
<p> Much has been written about the price spikes that plagued natural gas markets during the 1996-97 winter heating season. </p>
<p> In a study released last summer, %n4%n the A.G.A. notes the irony of high prices coupled with higher-than-normal overall </p>
<p> temperatures: "The 1996-97 winter heating season, on a national basis, was 3.5 percent warmer than normal and 6.1 percent warmer than the preceding winter." The A.G.A. also explains how the gas industry had drawn down storage inventories the year before to the lowest level in a decade, spawning higher-than-normal demand to refill storage throughout the summer of 1996. Then, when cold weather hit in November and December, many LDCs proved reluctant to withdraw significant gas volumes from storage "so early in the season." The A.G.A. ascribes that reluctance in part to "the role storage played in sustaining demand during the extended cold that [had] occurred" throughout the prior winter of 1995-96. It also cites index pricing practices as a cause for high prices in 1996-97. It notes that pricing for "substantial volumes of LDC gas supply" traditionally are based on first-of-the-month indices, despite bargains that may arise later in the month in the "aftermarket," and questioned whether the indices were set entirely at arm's length, or were supported by sufficient volume. </p>
<p> Were LDCs at fault? On one hand, the evidence discounts the idea that unregulated gas marketers manipulated the market. Schlesinger notes in his study that gas market concentration as measured by the Herfindahl-Hirschman Index fell each year from 1992 through 1996. He adds that 303 gas marketing companies were operating in unregulated North American gas markets by May 1997. The EIA puts the HHI for gas marketing firms at 243 for 1996, %n5%n far below the figure of 1,800 suggested in the Justice Department's Merger Guidelines as a sign of a highly concentrated market. </p>
<p> Nevertheless, while the EIA won't say that LDCs messed up, a study it released in August %n6%n seemed to offer no other reasonable conclusion for the 1996-97 winter heating season. </p>
<p> EIA agrees that at the start, after inventories had shrunk in the winter before (keeping prices high during the 1996 summer injection season); LDCs may have feared they would be caught short of storage toward the end of the coming winter. The EIA adds, however, that disruptions in railroad dispatch related to the merger between Southern Pacific and Union Pacific, appeared to have delayed coal shipments to power producers in Texas, adding to the pressure on gas prices. %n7%n Overall, the EIA finds that LDCs shunned withdrawals from downstream storage in the East Consuming Region (much of that storage is owned by the LDCs themselves). Instead, the LDCs turned to the spot market for supply in December, despite the high cost, rather than draw down storage volumes so early in the heating season, and even though storage was cheaper than spot prices. With the significant drop in December 1996 storage withdrawals, relative to the prior year, storage levels in the East Consuming Region equaled, and in some weeks actually exceeded, year-earlier values when prices were lower. The spot price for the Henry Hub in December 1996 averaged $3.78. </p>
<p> The EIA adds that "institutional factors" played a role: "Effective price signals to residential consumers are masked by specialized residential billing procedures, such as levelized billings, that are designed to avoid unexpected large increases in the monthly cost when possible." Why, for instance, should LDCs feel concern over high spot prices if they can pass along the expenses through gas cost recovery rates or a purchased gas adjustment clause? </p>
<p> Overall, according to the EIA, residential consumers paid $23.2 billion for natural gas during the 1996-97 heating season (em up from $21.2 billion the year before, representing an increase of more than 10 percent. </p>
<p> In fact, gas price fluctuations during the winter of 1996-97 prompted customers to ask for fixed-price options, even as pilot programs emerged for retail choice. Some regulators answered that wish, sometimes despite objections from the industry. </p>
<p> In New York, for example, Consolidated Edison Co. joined with Enron to oppose mandated fixed-price offerings. The utility predicted "confusion," while Enron claimed that a fixed-price option "distorts price signals" and would prove to be "a major hindrance" to competition. Regulators in New Jersey encouraged more conservative procurement practices, though it forces customers at risk to miss out on gas price savings. (See sidebar, "Low Price vs. Fixed Price.") </p>
<p> Electricity Futures: </p>
<p> Primed for Cross Hedging? </p>
<p> Last month, the New York Mercantile Exchange submitted two new electricity futures contracts (and two options contracts) for approval by the Commodity Futures Trading Commission. %n8%n One futures contract would be delivered at the Cinergy Control Area; the other at Entergy. (See sidebar, "NYMEX to the Rescue?") </p>
<p> These two proposals follow on the heels of the Minneapolis Grain Exchange, which earlier submitted electricity futures and options contracts to the CFTC, with a delivery point within a 30-mile radius of the Twin Cities, or the "TC GEN," to hedge against a cash market into the Mid-Continent Area Power Pool. %n9%n Terri Huffaker, vice president of marketing and public relations for the MGE, says the MAPP contract will offer NYMEX futures contracts at COB, Palo Verde, Cinergy and Entergy, by allowing delivery both on- and off-peak. (See sidebar.) </p>
<p> "Some commercial participants in the MAPP region approached us, including utilities and power marketers, asking for a risk-management vehicle. A marketer in the MAPP region really can't use the Palo Verde contract to hedge. We [MAPP] have different peaking seasons than Palo Verde." </p>
<p> Huffaker adds that the MGE worked with Northern States Power Co. and various MAPP-region power marketers to develop the contract. "MAPP did not work with us directly on contract design. We cannot claim we have a blanket endorsement from MAPP as an institution." </p>
<p> If all these new markets weren't enough to expand energy hedging opportunities, the NYMEX board of directors in January announced approval of a coal futures contract, to be launched later this year, with a trading unit of 37,200 MMBtu (heat content minimum of 12,000 Btu per pound), and a delivery point on the Ohio River between Milepost 206 and 317, or on the Big Sandy River. </p>
<p> Meanwhile, NYMEX had delayed filing yet another electricity futures </p>
<p> contract, deliverable at the PJM Interconnection. As explained by public relations officer Nachamah Jacobovits, NYMEX is waiting for the PJM companies to sort out all the trading rules for their new power pool, including the new locational marginal pricing scheme for electric transmission service approved for PJM in November by the Federal Energy Regulatory Commission, before launching a futures contract. "We're waiting to make sure that our contract reflects the cash market." </p>
<p> Cynthia Taylor, PJM's manager of customer relations and training, confirms the delay: "We will be implementing locational marginal pricing. There is no history for this type of market. I believe that is what has stalled the opening of the NYMEX contract." </p>
<p> Steven L. Brash, a spokesman for Cinergy, attributes the NYMEX decision to fix a contract at the Cinergy interconnection to his company's "very active and longer-time support for open transmission access" (hinting at the efforts of former PSI CEO James Rogers), and to the fact that the company maintains its own trading floor, 24 hours a day, seven days a week, operated through Cinergy's energy commodities business unit (not a separate subsidiary). </p>
<p> The Entergy contract, on the other hand, located near the Henry Hub, site of a premier gas spot market and a highly successful NYMEX futures contract for gas, offers the tantalizing prospect of cross-hedging between electricity and gas. </p>
<p> Entergy claims that its control area is well-equipped and positioned to handle physical delivery over its backbone of 500-kilovolt transmission lines and interconnections with 12 surrounding utilities. Shahid Malik, senior vice president and COO of Entergy Power Marketing Corp. (the utility's marketing and trading subsidiary), anticipates "a very good arbitrage opportunity" with the Henry Hub. </p>
<p> "A fairly large proportion of gas-fired generation is located in the South Central states," notes Malik. "This fact will allow us to hedge our trading of electricity with gas. You don't necessarily need to have a lot of nearby gas generation, but it does help." </p>
<p> When asked about the proposed NYMEX coal futures contract, and whether its location at a coal loading facility in Kentucky, close to the new electricity contract at the Cinergy control area, could possibly allow for power/coal cross-hedging, an EIA source declined comment, and Malik questioned whether the power contract would feature enough liquidity. He did volunteer, however, that the Cinergy contract could act as a proxy for New York and northeastern power markets in the event of a delay in starting up the PJM futures contract. </p>
<p> "They [NYMEX] have some real problems at PJM," Malik added. </p>
<p> Ben Schlesinger and John Herbert both remain cautious. "NYMEX is forging ahead," says Schlesinger, "but volumes will have to pick up through spark spread trading and arbitrage, before we get any real change." </p>
<p> Herbert acknowledges that Cinergy and Entergy are "very active wholesale markets for power, in terms of volume," but questions the market links between electricity and gas. </p>
<p> "Right now there's not much of a connection because of institutional constraints. That's why utilities are looking for assets. </p>
<p> "It's hard to cut deals, because nominations and contracts are not in synch. But if a company has both types of assets it can cut that knot." F </p>
<p> Bruce W. Radford is editor of Public Utilities Fortnightly. </p>
<p> Low Price vs. Fixed Price </p>
<p> Which Do Customers Want? Which Will Regulators Allow? </p>
<p> CONCERNED over gas price spikes during the winter of 1996-97, state regulators have called for more fixed-price </p>
<p> arrangements (em both in setting regulated retail gas rates and for portfolio supply contracting by gas utilities: </p>
<p> INDIANA. After hearing complaints about gas price volatility, state commission allows Indiana Gas Co. to back away from practice of buying all baseload gas supply at market-index prices, and instead buy a portion of gas supply under collars or fixed-price contracts. Case No. 37394-GCA54, 177 PUR4th 587, May 28, 1997 (Ind.U.R.C.). </p>
<p> IOWA. Utilities board allows MidAmerican Energy Co. to offer optional fixed-price sales service in a two-year pilot if the utility will absorb any gains and losses. Docket No. RPU-97-C (TF-97-201), 181 PUR4th 395, Dec. 10, 1997 (Iowa U.B.). </p>
<p> MICHIGAN. Regulators allow Michigan Consolidated Gas Co. to increase reliance on fixed-price gas supplies, but reject proposal to include a "volatility adjustment" in the gas cost recovery factor. Case No. U-11145, 179 PUR4th 333, Aug. 13, 1997 (Mich.P.S.C.). </p>
<p> NEW JERSEY. Stipulation says that, assuming normal weather, Public Service Electric &amp; Gas Co. will acquire up to 50 percent of residential gas supply through fixed-price contracts or financial derivatives to hedge or lock in price, such as floors, swaps, caps, collars, puts and calls. Board acknowledges that customers could miss out on some price savings. Docket No. GR96070554, 179 PUR4th 326, July 30, 1997 (N.J.B.P.U.). </p>
<p> NEW MEXICO. PUC fines Public Service Co. of New Mexico for understating gas supply costs. Finds that near-total reliance on spot market purchases led to a price spike in retail gas rates. Case No. 2752, 175 PUR4th 393 (N.M.P.U.C.). </p>
<p> NEW YORK. Rule requires gas utilities to review procurement practices and submit plans for fixed-price service, but allows LDCs to limit fixed prices to 10 percent of customers and to exclude non-core and low-volume (cooking only) customers, who would not likely benefit. Case 97-G-0600, 180 PUR4th 553, Oct. 7, 1997 (N.Y.P.S.C.). </p>
<p> VIRGINIA. Pilot program allows Roanoke Gas Co. to use financial instruments to hedge against prices for up to 25 percent of normal wintertime gas demand, excluding demand supplied from storage withdrawals. Case No. PUE970420, July 24, 1997, 179 PUR4th 364 (Va.S.C.C.). </p>
</p>
<p> NYMEX to the Rescue? </p>
<p> New Contracts Could Hedge Against Gas </p>
<p> PROPOSED contracts: </p>
<p> • Cinergy Control Area (NYMEX). 736 MWh, Peak hours (delivery 7A.M. to 11P.M., Eastern time). </p>
<p> • Entergy Control Area (NYMEX). 736 MWh, peak hours (delivery 6 A.M. to 10 P.M., Central time). </p>
<p> • PJM Interconnection (NYMEX). On hold, pending implementation in April 1998 of locational marginal pricing for transmission and development of experience in cash market. </p>
<p> • Twin Cities (Minneapolis Grain Exchange). 736 MWh, peak hours (delivery 6 A.M. to 10 P.M., Central time); 368 MWh, off-peak hours (delivery 10 P.M., to 6 A.M., Central time). </p>
<p> 1 John Herbert, James Thompson, and James Todaro, "Recent Trends in Natural Gas Spot Prices," Natural Gas Monthly, December 1997, p. vii (U.S.E.I.A.). </p>
<p> 2 Natural Gas Weekly Market Update, Feb. 9, 1998 (U.S.E.I.A.). </p>
<p> 3 Benjamin Schlesinger, "Natural Gas Industry Trends: Commoditizing Everything in Sight," posted by New York Mercantile Exchange, see <a href="http://www.nymex.com/ein/ein.html">www.nymex.com/ein/ein.html</a>. </p>
<p> 4 LDC System Operations and Supply Portfolio Management During the 1996-97 Winter Heating Season, A.G.A. Issue Brief 1997-06, June 10, 1997. </p>
<p> 5 William Trapmann and James Todaro, "Natural Gas Residential Pricing Developments During the 1996-97 Winter," Natural Gas Monthly, Aug. 1997, p. l (U.S.E.I.A.). </p>
<p> 6 Ibid. </p>
<p> 7 Herbert, et al., see note 1. </p>
<p> 8 63 Fed.Reg. 7406, Feb. 13, 1998. </p>
<p> 9 63 Fed. Reg. 3543, Jan. 23, 1998. </p>
<p></p>
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<a href="/tags/american-gas-association">American Gas Association</a><span class="pur_comma">, </span><a href="/tags/cinergy">Cinergy</a><span class="pur_comma">, </span><a href="/tags/citi">Citi</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/dc">DC</a><span class="pur_comma">, </span><a href="/tags/eia">EIA</a><span class="pur_comma">, </span><a href="/tags/eia-0">EIA</a><span class="pur_comma">, </span><a href="/tags/energy-information-administration">Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/energy-information-administration-0">Energy Information Administration</a><span class="pur_comma">, </span><a href="/tags/entergy">Entergy</a><span class="pur_comma">, </span><a href="/tags/federal-energy-regulatory-commission">Federal Energy Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/interconnection">Interconnection</a><span class="pur_comma">, </span><a href="/tags/irg">IRG</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/james-rogers">James Rogers</a><span class="pur_comma">, </span><a href="/tags/midamerican">MidAmerican</a><span class="pur_comma">, </span><a href="/tags/midamerican-energy">MidAmerican Energy</a><span class="pur_comma">, </span><a href="/tags/new-jersey">New Jersey</a><span class="pur_comma">, </span><a href="/tags/pjm">PJM</a><span class="pur_comma">, </span><a href="/tags/pjm-interconnection">PJM Interconnection</a><span class="pur_comma">, </span><a href="/tags/rgi">RGI</a><span class="pur_comma">, </span><a href="/tags/shahid-malik">Shahid Malik</a><span class="pur_comma">, </span><a href="/tags/southern-california-gas-co">Southern California Gas Co.</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/str">STR</a><span class="pur_comma">, </span><a href="/tags/us-energy-information-administration">U.S. Energy Information Administration</a> </div>
</div>
Sun, 15 Mar 1998 05:00:00 +0000puradmin9746 at https://www.fortnightly.comNews Digesthttps://www.fortnightly.com/fortnightly/1998/03/news-digest
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Lori A. Burkhart, Phillip S. Cross and Beth Lewis</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - March 1 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> State Legislatures </p>
<p> UTILITY HOUSE CALLS. Michigan Gov. John Engler (R) signed into law a bill making it a felony to impersonate a utility employee to enter private property for criminal purposes. The new law calls for those convicted to be imprisoned for not more than two years and to pay a maximum fine of $1,000, or both. </p>
<p> ELECTRIC RESTRUCTURING. Illinois Gov. Jim Edgar (R) signed into law an electric restructuring bill for the state. Edgar noted that concerns over the bill were addressed by the state's two largest utilities, Commonwealth Edison and Illinois Power Co. The companies agreed not to sell any power plants before a rate cut becomes effective Aug. 1. The bill, signed in December, calls for a 20-percent residential rate decrease for the two utilities; 15 percent on Aug. 1 and 5 percent on May 1, 2002. </p>
<p> Federal Agencies </p>
<p> MIDWEST ELECTRIC FUTURES. The Minneapolis Grain Exchange asked the Commodity Futures Trading Commission to approve its listing of electric futures and options contracts reflecting the value of electricity in seven midwestern states and two Canadian provinces. The contracts would be based on electric delivered in Minneapolis-St.Paul at facilities owned by Northern States Power. One contract would reflect the value of 736 megawatt-hours of peak electricity; the other would reflect off-peak deliveries of 368 Mwh. </p>
<p> Studies &amp; Reports </p>
<p> HIGHER ELECTRIC RATES. Residents of Kentucky may pay much more for electricity because of changes in regulation of the power industry, according to a study released by agricultural economists with the University of Kentucky College of Agriculture. Electrical rates and usage patterns in four rural Kentucky counties were analyzed and showed that rates could increase almost 45 percent. Study projected probable effects on families, businesses and local economies if federal deregulation results in a more uniform national price for electricity. </p>
<p> RISING GAS USE. The American Gas Association released a forecast that said natural gas consumption would reach an all-time high in 1998, surpassing the record levels set in 1972. The A.G.A. sees natural gas use reaching 23.3 quadrillion Btu, or quads this year. </p>
<p> Business Wire </p>
<p> THE MUNICIPAL GAS AUTHORITY OF GEORGIA, representing 75 public agencies in three states, entered a 10-year natural gas supply contract with Columbia Energy Services, a Columbia Gas System subsidiary. The Gas Authority began purchasing 12 billion BTU per day of natural gas from Columbia on Jan. 1. </p>
<p> Eastern Enterprises agreed to acquire Essex County Gas Co. in a stock-for-stock transaction. Based on shares outstanding Dec. 1, the transaction has an equity value of $80.5 million, or $47.50 per share. When the merger is complete, Essex County Gas will operate as a wholly owned subsidiary of Eastern and as a sister company of Boston Gas Co. </p>
<p> Standard &amp; Poor's will replace Union Electric Co. in the S&amp;P 500 Index with Ameren Corp., the new company to be formed by the merger of Union Electric Co. and CIPSCO Inc. </p>
<p> Citizen Utilities acquired Ogden Telephone Co. by purchasing Odgen's common stock for about $23.5 million. Holders of a single share of Odgen common stock will receive about 18.5 shares of Citizen's common stock. </p>
<p> Otter Tail Power Co. will invest almost $3 million in energy conservation programs over the next two years. The investment, following approval by the Minnesota Department of Public Service, will be used for rebates, grants, energy-saving projects and other energy-efficient services. </p>
<p> Cinergy Services Inc. signed a $26-million, multi-year contract with Convergent Group for consulting and systems integration services. </p>
<p> CNG International Corp., a subsidiary of Consolidated Natural Gas Co., acquired interests in two Argentina gas companies and one Argentina electric company for $78 million. CNG purchased 12.5-percent interests in two gas utility holding companies, Sodigas Pampena and Sodigas Sur, and a 20-percent interest in Buenos Aires Energy Co., from CEI Citicorp Holdings Sociedad Anonima. </p>
<p> FERC </p>
<p> GAS PIPELINE CERTIFICATION. Independence Pipeline Co. </p>
<p> filed an amendment with the commission to its application to build 400 miles of 36-inch diameter pipe from Ohio to Pennsylvania. The amendment seeks authority to negotiate tariff provisions and for one major route change to the eastern portion of the original pipeline route. Independence Pipeline is a general partnership formed by subsidiaries of the Coastal Corp.'s ANR Pipeline Co., Williams' Transcontinental Gas Pipe Line Corp., and National Fuel Gas Co. </p>
<p> STRANDED COSTS; MUNICIPALIZATION. Commission staff rec- </p>
<p> ommended that the city of Las Cruces, N.M. pay $29.4 million to El Paso Electric Co. if the city condemns EPE's electric distribution facilities and forms a municipal electric utility. FERC staff concluded that EPE had a reasonable expectation of continuing to serve Las Cruces. </p>
<p> Mergers &amp; Acquisitions </p>
<p> SETTING TAKEOVER PRICE. Western Resources Inc. and </p>
<p> Kansas City Power &amp; Light Co. postponed their shareholder meetings set for Jan. 21 to vote on their proposed merger. Utility analysts say the delay is needed because of disagreement over the price that Western Resources will pay for Kansas City P&amp;L. In the year since the merger was announced, the value (em based on a formula agreed to at the time (em has risen beyond the formula's parameters. Now, Western Resource would have to pay $36 per share; it doesn't believe it should pay more than $32 per share. </p>
<p> CHOOSING COMPANY NAME. Pacific Enterprises and Enova </p>
<p> Corp. announced the new name of their soon-to-be combined company: Sempra Energy, from the Latin word "semper," which means always. Stephen L. Baum, Enova president and CEO said Sempra was concise and easy to communicate in several languages. </p>
<p> State PUCs </p>
<p> GAS COST SECURITIZATION. The Montana Public Service </p>
<p> Commission issued a procedural order setting March 18 as the target date for a final order on a Montana Power Co. application. The order will address transition bonds for recovery of gas utility transition costs. Docket No. d97.1, Order No. 6035, Dec. 12, 1997. </p>
<p> PREDATORY PRICING. The California Public Utilities Com- </p>
<p> mission ruled that predatory pricing will not occur in the state's wholesale electric generation market when Southern California Edison Co. auctions its 12 fossil fuel generating plants. The PUC said that predatory pricing requires the ability to eventually charge supra-competitive prices to recoup the initial investment in below-cost, predatory rates. Plant buyers must get market-based pricing approval from the FERC to sell power from the plants. a.96-11-046, d. 97-11-075, Nov. 19, 1997 (Cal.P.U.C.). </p>
<p> POWER PLANT AUCTIONS. The New York Public Service Com- </p>
<p> mission has ruled that Orange and Rockland Utilities Inc. can bid in the auction of its own plants, subject to </p>
<p> certain conditions. The commission said the utility could participate in the auction because it does not possess horizontal market power and consumers might benefit. The commission made the ruling while approving the utility's revised restructuring plan, which contains an accelerated schedule for full retail access for all customers by May 1, 1999. Large customers can choose alternate suppliers under a special program one year earlier. Case 96-e-0900, Nov. 26, 1997 (N.Y.P.S.C.). </p>
<p> RETURN ON EQUITY. State regulators rejected calls by Public </p>
<p> Service Company of New Hampshire for "a premium rate of return on equity" to reflect increased risk caused by the state's electric restructuring plan. The commission rejected the utility's request for an ROE allowance of 17 to 19 percent and instead set the earnings level at 11 percent. The PUC also approved a temporary rate cut of 6.87 percent for the utility. The commission said the failure by the company to acknowledge that the price of its stock had fallen well before the issuance of the states' electric restructuring plan in 1996 "strains the bounds of credulity." dr 97-059, Order No 22,784, Nov. 6, 1997 (N.H.P.U.C.). </p>
<p> GAS PILOT PROGRAM. The Michigan Public Utilities Com- </p>
<p> mission has authorized Consumers Energy Co. to implement a voluntary experimental pilot program giving up to 300,000 sales customers the opportunity to choose an alternative gas supplier. To protect existing customers, the utility will freeze its noncommodity charges and gas commodity rate for three years. The plan allows the utility to share with ratepayers earnings attributable to noncommodity charges that exceed established levels. Limited base-rate reviews are also provided for in case of major changes in regulations, accounting requirements or taxes. Case No. u-11599, Dec. 19, 1997 (Mi.P.S.C.). </p>
<p> GAS CHOICE PROGRAMS. The Pennsylvania Public Utility </p>
<p> Commission said Equitable Gas Co. can implement a program allowing supply choice for all natural gas customers. The program marks the first full-scale gas unbundling plan to come before the commission. The new plan provides for full assignment to marketers of upstream capacity costs using a three-tier pool structure based on usage. According to the commission, the mandatory assignment of capacity at a federally approved rate would eliminate stranded costs and promote continued system reliability. r-00963858, Dec. 4, 1997 (Pa.P.U.C.). </p>
<p> TELCO EQUITY RETURNS. The Vermont Public Service Board </p>
<p> has reduced rates for a newly formed rural telecommunications local exchange carrier, Vermont Telephone Co. Inc., by 8.62 percent. It also set rate of return on equity at 11.9 percent, the low end of the range produced under the discounted cash flow method accepted in the case. The board said the lower figure was appropriate because the state's rural carriers appeared to face little threat from new market entrants. Docket No. 5904, Nov. 11, 1997 (Vt.P.S.B.). </p>
<p> TELECOM RESALE DISCOUNTS. The New Jersey Board of Public </p>
<p> Utilities issued a generic ruling governing interconnection rates charged by incumbent local exchange telephone carriers to competitive carriers. For unbundled network services, the board adopted the same principles underlying the total element long-run incremental cost method used by the Federal Communications Commission. It said the TELRIC method will reduce the incumbent LEC's ability to engage in anticompetitive behavior. The BPU set the wholesale discount at 17.04, for resellers using Bell Atlantic of New Jersey with operator service and at 20.03 percent without. Docket No. tx95120631, Dec. 2, 1997 (N.J.B.P.U.). </p>
<p> TELECOM REVENUES. The New Jersey Board of Public Utili- ties approved a plan by Jersey Central Power and Light Co. to offer fiber-optic and other telecommunications services to carriers through a corporate affiliate, but said that revenues from the arrangement should be used to reduce stranded costs rather than applied as a reduction to transmission and distribution revenue requirements. Docket No. ee97050350, Dec. 17, 1997 (N.J.B.P.U.). </p>
<p> TELCO PRICE CAPS. The Maine Public Utilities Commission </p>
<p> decided not to modify its price-cap plan for New England Telephone and Telegraph Co. to account for revenue changes that occur when customers migrate between service offerings as prices are raised and lowered under an index-rate mechanism. The commission concluded that the LEC should bear all the risks and reap all the benefits from its conscious choice to reduce some rates more than others. A method to shield the utility from such risk is inappropriate under incentive regulation, the PUC said. Docket No. 97-079, Nov. 25, 1997 (Me.P.U.C.). </p>
<p> Courts </p>
<p> PILOT PROGRAM REFUNDS. The Ohio Supreme Court ruled state regulators cannot order refunds of charges levied under a weather normalization program run by Columbia Gas of Ohio to levelize customer bills. However, consumer response to the experiment was negative due to higher-than-expected bills during an unusually warm winter when the program began. Some customers said the company had mislead them and had reaped a windfall. The court ruled the commission lacked authority to order refunds of rates paid under approved schedules. Lucas County Comm'rs v. Ohio PUC, 686 N.E.2d 501, Dec. 3, 1997 (Ohio). </p>
<p> APPLIANCE REPAIR SERVICE. The Iowa Supreme Court upheld a recently enacted state law prohibiting public utility companies from using rate-supported assets or employees in the provision of non-utility appliance repair and installation activities. The existing code had only required that a public utility should provide services to non-utility affiliates in a manner that "minimizes cross-subsidization or unfair competitive advantage." The court found that the additional restriction was a legitimate attempt by the state to place state utilities on a level playing field with other contractors providing similar services. UtiliCorp United Inc. v. Iowa Utils. Bd., 570 N.W.2d 451, Nov. 26, 1997 (Iowa). </p>
<p> Lori A. Burkhart and Phillip S. Cross are contributing legal editors and Beth Lewis is editorial assistant. </p>
</p>
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<div class="field-items">
<a href="/tags/ameren">Ameren</a><span class="pur_comma">, </span><a href="/tags/american-gas-association">American Gas Association</a><span class="pur_comma">, </span><a href="/tags/aps">APS</a><span class="pur_comma">, </span><a href="/tags/cap">CAP</a><span class="pur_comma">, </span><a href="/tags/cash-flow">cash flow</a><span class="pur_comma">, </span><a href="/tags/cinergy">Cinergy</a><span class="pur_comma">, </span><a href="/tags/cip">CIP</a><span class="pur_comma">, </span><a href="/tags/cips">CIPS</a><span class="pur_comma">, </span><a href="/tags/citi">Citi</a><span class="pur_comma">, </span><a href="/tags/citicorp">Citicorp</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/communication">Communication</a><span class="pur_comma">, </span><a href="/tags/consumers-energy">Consumers Energy</a><span class="pur_comma">, </span><a href="/tags/el-paso-electric">El Paso Electric</a><span class="pur_comma">, </span><a href="/tags/epa">EPA</a><span class="pur_comma">, </span><a href="/tags/epe">EPE</a><span class="pur_comma">, </span><a href="/tags/ev">EV</a><span class="pur_comma">, </span><a href="/tags/federal-communications-commission">Federal Communications Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/gas">GAS</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/ice">ICE</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/kansas-city-power-light">Kansas City Power &amp; Light</a><span class="pur_comma">, </span><a href="/tags/maine-public-utilities-commission">Maine Public Utilities Commission</a><span class="pur_comma">, </span><a href="/tags/national-fuel-gas">National Fuel Gas</a><span class="pur_comma">, </span><a href="/tags/new-jersey">New Jersey</a><span class="pur_comma">, </span><a href="/tags/ot">OT</a><span class="pur_comma">, </span><a href="/tags/pacific-enterprises">Pacific Enterprises</a><span class="pur_comma">, </span><a href="/tags/ppl">PPL</a><span class="pur_comma">, </span><a href="/tags/ram">RAM</a><span class="pur_comma">, </span><a href="/tags/rep">REP</a><span class="pur_comma">, </span><a href="/tags/res">RES</a><span class="pur_comma">, </span><a href="/tags/rgi">RGI</a><span class="pur_comma">, </span><a href="/tags/roe">ROE</a><span class="pur_comma">, </span><a href="/tags/sp">S&amp;P</a><span class="pur_comma">, </span><a href="/tags/sempra">Sempra</a><span class="pur_comma">, </span><a href="/tags/sempra-energy">Sempra Energy</a><span class="pur_comma">, </span><a href="/tags/southern-california-edison">Southern California Edison</a><span class="pur_comma">, </span><a href="/tags/str">STR</a><span class="pur_comma">, </span><a href="/tags/transco">Transco</a><span class="pur_comma">, </span><a href="/tags/ver">VER</a><span class="pur_comma">, </span><a href="/tags/williams">Williams</a> </div>
</div>
Sun, 01 Mar 1998 05:00:00 +0000puradmin9739 at https://www.fortnightly.comNews Digesthttps://www.fortnightly.com/fortnightly/1998/02-0/news-digest
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Lori A. Burkhart, and Phillip S. Cross</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - February 15 1998</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> POWER PLANT SALE. Central Maine Power Co. has agreed to </p>
<p> sell its hydroelectric, fossil and biomass power plants totaling 1,185-MW of generating capacity to FPL Group, the holding company of Florida Power and Light. The sale price of $846 million exceeds book value and could permit up to a 10-percent rate cut for customers by the end of the year. </p>
<p> OHIO/TEXAS DEAL. Ohio-based American Electric Power </p>
<p> Co. and Texas-based Central and South West Corp. on Dec. 22 announced that they have entered an agreement to merge, creating a company with a total market capitalization of about $28.1 billion. The companies anticipate merger-related savings of about $2 billion over a ten-year period but estimated 1,300 out of a total of 25,000 domestic jobs will be lost. </p>
<p> CAJUN BANKRUPTCY. Entergy Gulf States has acquired the </p>
<p> 30-percent share of the River Bend nuclear power plant formerly owned by Cajun Electric Power Cooperative Inc. Entergy now has 100-percent ownership of the plant. The acquisition was part of a larger agreement ending a series of disputes between the two companies that spawned litigation for eight years. Entergy Gulf States took title to Cajun's interest in River Bend from Cajun's trustee in bankruptcy, Ralph R. Mabey, at the direction of the Rural Utilities Service, formerly the Rural Electrification Administration, the major secured creditor in Cajun's ongoing bankruptcy case. </p>
<p> PLANS TERMINATED. Baltimore Gas and Electric Co. and </p>
<p> Potomac Electric Power Co. have terminated plans to merge to form a new company, Constellation Energy Corp. The two companies cited financial conditions imposed by the District of Columbia and Maryland commissions as reason to cancel their plans. "We have tried unsuccessfully to obtain reconsideration of these conditions," said BGE's Chairman and CEO Christian H. Poindexter and PEPCO's President and CEO John M. Derrick Jr. "But [we] now conclude that a favorable outcome cannot be expected within a reasonable period, if at all." The proposed merger also was plagued by lawsuits filed by union workers. </p>
<p> Power Pools &amp; ISOs </p>
<p> NEW YORK POWER POOL. The New York Power Pool on </p>
<p> Dec. 19 filed supplemental information on plans by member systems to create an independent system operator. It has asked the FERC for approval by March 31, 1998, to allow the ISO to become operational by June 30, 1998. The proposal calls for use of locational-based marginal pricing for both electricity sold in the competitive spot market and for transmission service. </p>
<p> SOUTHWEST POWER POOL. The Southwest Power Pool on </p>
<p> Dec. 19, 1997 filed at the FERC its open-access electric transmission tariff, which would allow one-stop shopping for short-term firm and nonfirm point-to-point transmission service across seven southwestern states. If approved, the tariff would become effective in April, and would partly supersede present tariffs on file by member utilities. The tariff provides for rates designed on a distance-based "megawatt-mile" method, which establishes a link between the reservation, scheduling and compensation for transmission service and the anticipated impact of such service on the transmission system. In so doing, the megawatt-mile method replaces the present contract-path method and addresses rights to available transfer capability of the interconnected transmission system. </p>
<p> Environmental Issues </p>
<p> NOx ABATEMENT. New York's investor-owned utilities and </p>
<p> independent power producers have agreed to reduce nitrogen-oxide emissions from power plants. Under the settlement, the utilities and the IPPs have decided how to divide the state's annual allotment of NOx emissions for the years 1999 through 2002. They anticipate the plan will allow New York to reach its goal of reducing NOx emissions by 44 percent by 1999 and by 62 percent by 2003, compared with 1990 levels. </p>
<p> Federal Agencies </p>
<p> PURCHASED-POWER ARBITRATION. A federal arbitrator has </p>
<p> ruled in favor of Basin Electric Power Cooperative in a purchase-power contract dispute with Montana Power Co. Arbitrator Jon Lotis ruled valid and binding the contract requiring Montana Power to purchase 98 MW of power from the co-op over 15 years for about $100 million at present market conditions. Basin Electric also was awarded more than $6.3 million in damages plus interest for the first year of the contract. "I think it also sends a message to others who might be thinking about reneging on power contracts in these unsettled times," said Bob McPhail, Basin Electric general manager. "It is a message that needs to be sent throughout the country as the electric utility industry undergoes deregulation." </p>
<p> State Legislatures </p>
<p> VIRGINIA RESTRUCTURING. Virginia Sen. Jackson E. Reasor </p>
<p> Jr., chairman of a joint electric deregulation committee, plans to introduce an electric restructuring bill in the 1998 Virginia legislative session, which runs from Jan. 14 to March 14, for consideration in 1999. Meanwhile, Virginia Electric Power Co. plans to introduce legislation in 1998. </p>
<p> OHIO RESTRUCTURING. The Ohio Legislature's Joint Select </p>
<p> Committee on Electric Deregulation has released its report, Competition: Ohio's Choice, which calls for full retail electric competition starting Jan. 1, 2000. For five years, ending Dec. 31, 2004, Ohio would be divided into retail marketing areas. Generation service for all customers in each area would be aggregated and bid out. </p>
<p> Courts </p>
<p> STRANDED COSTS. The Massachusetts Supreme Judicial Court has reversed and remanded an order by the state's Department of Public Utilities (now the Department of Telecommunications and Energy) that denied recovery of stranded costs after the Stow Municipal Electric Department "municipalized" and took over facilities of Hudson Light and Power Department to lower rates. The move saddled Hudson with unrecovered costs for buying high-cost power from the Massachusetts Municipal Wholesale Electric Co. State regulators had said that Hudson's rates would decline anyway, whether or not it lost the Stow account, but the court said that ignored the fact that Hudson ratepayers would still pay higher rates with Stow's departure from the system. Stow Mun. Elec. Dept. v. Mass. DPU, Nos. sjc-07350 et al., Dec. 30, 1997 (Mass.) 1997 wl 792398. </p>
<p> COAL BUY-OUT COSTS. An Illinois appeals court has reversed a state commission order that had allowed Central Illinois Public Service Co. and Central Illinois Light Co. to recover coal supply contract buy-out payments through the fuel cost adjustment clause. It said that such cost could not qualify as direct costs of fuel. Archer-Daniels-Midland Co. v. Ill. Commerce Comm'n, No. 3-97-0170, Nov. 24, 1997 (Ill.App.3d.Dist.) 1997 wl 731547. </p>
<p> TELCO PRICE-CAP PLANS. Reversing an order by the state's Commonwealth Court, the Pennsylvania Supreme Court has in effect reinstated a 1994 state PUC order that approved a price-cap plan for Bell Atlantic-Pennsylvania, with the cap keyed to the rate of inflation minus a 2.93 percent offset for productivity. The lower court (669 A.2d 1029) had said the PUC lacked evidence to find that certain services were competitive, and had required the PUC to adjust the offset by an "input price differential" to reflect alleged cost differences between the telecommunications industry and the economy as a whole. Popowsky v. Pa. PUC, Nos. 101 et al., Dec. 24, 1997 (Pa.) 1997 wl 786906. </p>
<p> Business Wire </p>
<p> CMS Energy will begin an experimental pilot program allowing up to 300,000 natural gas customers to chose their gas suppliers over the next three years. According to CMS, the gas choice plan is the largest and most far-reaching of its kind. </p>
<p> Energis Resources has secured more than 700 new business customers since the beginning of the Pennsylvania Pilot Program. Energis Resources, a subsidiary of Public Service Enterprise Group Inc., was one of 43 electric generation suppliers licensed to participate. The company's new business customers translate into more than 350 million kilowatt-hours in sales. </p>
<p> Electric Lite signed a deal with Illinova Energy Partners to purchase power for its customers in Portland General Electric's pilot program. Electric Lite enrolled nearly 1,500 customers and began delivering power on Dec. 1, 1997. The power supply agreement is a fixed-price, full-requirements contract. Illinova will serve as Electric Lite's scheduler. </p>
<p> El Paso Field Services, a business unit of El Paso Energy Corp., purchased a natural gas gathering and processing system for $196.5 million from TPC Corp., a wholly owned subsidiary of PacifiCorp. </p>
<p> Air Products and Chemicals Inc. signed two, multi-year contracts to provide on-site gas management services to the LaPorte, Texas E.I. du Pont de Nemours and Co. plant and the Chaulk River Atomic Energy Canada Limited Facility. Services include placing Air Products employees at both customers' sites to assume responsibility for the facilities' industrial and specialty gas requirements, daily deliveries, logistical support and key administrative operations. </p>
<p> Madison Gas and Electric Co. issued a request for proposal for construction of up to 100 megawatts of electric capacity to be provided by a new power plant. MGE is promoting construction of a single, 500-MW unit. </p>
<p> State PUCs </p>
<p> POWER CHOICE PLANS. The Michigan commission approved </p>
<p> plans by Consumers Energy Co. and Detroit Edison Co. to allow all customers to choose electric suppliers, as required under the PSC's 1997 restructuring ruling, which requires a phase-in through 2001. The PSC directed the utilities to use a bidding process to recover stranded costs and to allocate open-access load among participating </p>
<p> customers during the phase-in. Bid rules must contain a mandatory minimum bid requirement of 0.5 cents per kilowatt-hour for transition cost recovery. It also authorized the electric utilities to suspend their existing power supply cost-recovery mechanisms during the retail access phase-in period. Case Nos. u-11451, u-11452 (direct access plans), u-11449, u-11453 (power supply adjust.), Oct. 29, 1997 (Mi.P.S.C.). </p>
<p> STRANDED-COST TRUE-UP. The Michigan PSC has adopted a true-up mechanism that compares stranded-cost estimates and the actual prices paid by direct-access customers for power. Case No. u-11454, Oct. 29, 1997 (Mi.P.S.C.). </p>
<p> CONSUMER EDUCATION. The Maine commission proposed rules to implement a consumer education program on plans to open electricity to retail competition, now set for March 1, 2000. The proposal sets a maximum funding level for the program of $1.6 million, or $3 per capita. The plan would have transmission and distribution utilities provide funds for educational activities and recover the amount from ratepayers. The companies will distribute the required market information, primarily as bill inserts. Docket No. 97-583, Nov. 3, 1997 (Me.P.U.C.). </p>
<p> POWER CHOICE PLANS. The New York commission approved </p>
<p> modified rate and restructuring plans for both Rochester Gas &amp; Electric Corp., and Orange and Rockland Utilities Inc. Both plans allow for the development of competition and provide significant rate reductions of more than $80 million during the transition to a fully competitive electric market. Re Docket Nos. 97097, 96e0898, 96e0900, Nov. 25, 1997 (N.Y.P.S.C). </p>
<p> PERFORMANCE-BASED RATES. The Michigan commission will </p>
<p> allow Consumers Energy Co. to implement a rate freeze and a performance-based rate mechanism for distribution and customer charges when competitive suppliers serve 5 percent of its load. The PBR mechanism would tie base-rate adjustments to changes in a weighted composite of Producer Price Index data for capital investment, electric transmission and distribution equipment and compensation for utility and transportation employees. This method will measure cost changes experienced by the utility rather than by its ratepayers. Case No. u-11456, Oct. 29, 1997 (Mi.P.S.C.). </p>
<p> COGENERATION. The Maine commission plans to update its </p>
<p> rules governing cogeneration and small power production purchases by electric utilities. Maine's new electric restructuring law relieves utilities of any obligation to enter long-term agreements to buy power from QFs, but requires the PUC to continue to establish short-term energy-only rates to fulfill the terms of existing QF contracts. The proposal would eliminate utility filing requirements for long-term load forecasts, energy resource plans and avoided-cost calculations. It would abandon existing avoided-cost methods in favor of a choice between two alternatives: (a) a method based on clearing prices at the New England Independent System Operator, or (b) an administrative determination bolstered by new market information. Docket No. 97-794, Oct. 31, 1997 (Me.P.U.C.). </p>
<p> ELECTRIC METER READING. The New Jersey board has </p>
<p> approved a proposal by Rockland Electric Co. to provide monthly meter readings for its residential customers, most of whom are currently on bimonthly billing, to adapt to pricing options offered by alternative suppliers. The company said the switch would be "revenue neutral," due to an agreement with its workers through the International Brotherhood of Electric Workers local. Under the agreement, the union will agree to a new meter reading job classification at a lower hourly wage. All incumbent meter readers are grandfathered under the agreement and the utility agreed to discontinue the use of outside contractors in the meter reading function. Docket No. et97080583, Nov. 6, 1997 (N.J.B.P.U.). </p>
<p> GAS COST RECOVERY. The Wisconsin commission has approved a performance-based gas cost recovery mechanism for Wisconsin Gas Co. It will tie recovery of commodity costs, supplier reliability premiums, storage costs pipeline capacity costs and risk management costs to observed performance against commodity price indices drawn from the publication Inside FERC and other operational indicators such as expected injection volumes for storage. Docket No. 6650-gr-113, Oct. 30, 1997 (Wi.P.S.C.). </p>
<p> BABY BELL LONG DISTANCE. The Washington commission issued a policy statement on tests that U S WEST Communications Inc. must pass to qualify to offer competitive interLATA long-distance service under the Federal Telecommunications Act of 1996. It will examine approved interconnection arrangements between the U S WEST and competitors in local markets to ensure local access service is adequate and a significant level of competition exists. Docket No. ut-970300, Oct. 24, 1997 (Wash.U.T.C.). </p>
<p> ELECTRIC HOLDING COMPANY. The Arizona Corporation Commission allowed Tucson Electric Power Co. to form a holding company, UniSource Energy. Commissioners approved a financing application that allows TEP to replace the credit agreement resulting from a 1991 bankruptcy court action and to refinance $184 million in bonds. Nov. 19, 1997 (Ariz.C.C.). </p>
<p> UNIVERSAL TELEPHONE SERVICE. The New Jersey board has </p>
<p> adopted a definition of universal service for the telecommunications industry. The definition includes: a white pages listings, voice-grade access to the public network; the ability to place and receive calls; touch-tone or dual-tone multifrequency signaling or its equivalent; single-party service; access to emergency, operator and inter-exchange services; and access to directory assistance. The board said that further study was needed to set the appropriate level of local usage to include in the definition. It also ruled that carriers receiving universal support for lifeline service are prohibited from disconnecting customers for nonpayment of toll charges. Docket No. tx95120631, Oct. 29, 1997 (N.J.B.P.U.). </p>
<p> BABY BELL LONG DISTANCE. The Florida PSC found that Bell </p>
<p> South Telecommunications Inc. has met only some of the requirements necessary to enter the interLATA long-distance market under the Federal Telecommunications Act of 1996. It found that newly certified competitive carriers were serving about 27,000 business subscriber access lines in the state, but that Bell South had failed to submit sufficient evidence of competitive local service. It said Bell South was having problems fulfilling requests from new market entrants and meeting other requirements set up by the Federal Communications Commission. Docket No. 960786-tl, Order No. psc-97-1459-fof-tl, Nov. 19, 1997 (Fla.P.S.C.). </p>
<p> CABLE TV SUBSIDY. The Massachusetts Department of Tele- </p>
<p> communications and Energy has opened an investigation into whether Boston Edison Co. improperly subsidized a cable television and telecommunications venture, Residential Communications Network, through an unregulated subsidiary, The Boston Energy Technology Group, by investing more money than authorized, or for lines of business not previously approved. (D.P.U. 97-95). </p>
<p> Boston Edison, through its affiliate, Boston Energy Technology Group, is involved in a joint venture with RCN to provide cable and telecom services in Massachusetts, and has granted access to RCN to fiber-optic network lines, rights of way and customer lists. In 1993 the department had granted authority to Boston Edison to invest $45 million in Boston Energy Technology Group only for three purposes: demand-side management, electric vehicles and electric generation services. </p>
<p> News digest compiled by Lori A. Burkhart and Phillip S. Cross, </p>
<p> contributing legal editors, and Beth Lewis, editorial assistant. </p>
</p>
<p></p>
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<a href="/tags/american-electric-power">American Electric Power</a><span class="pur_comma">, </span><a href="/tags/baltimore-gas-and-electric">Baltimore Gas and Electric</a><span class="pur_comma">, </span><a href="/tags/bankruptcy">bankruptcy</a><span class="pur_comma">, </span><a href="/tags/bge">BGE</a><span class="pur_comma">, </span><a href="/tags/cap">CAP</a><span class="pur_comma">, </span><a href="/tags/central-maine-power">Central Maine Power</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/communication">Communication</a><span class="pur_comma">, </span><a href="/tags/constellat">Constellat</a><span class="pur_comma">, </span><a href="/tags/constellation">Constellation</a><span class="pur_comma">, </span><a href="/tags/constellation-energy">Constellation Energy</a><span class="pur_comma">, </span><a href="/tags/consumers-energy">Consumers Energy</a><span class="pur_comma">, </span><a href="/tags/deregulation">Deregulation</a><span class="pur_comma">, </span><a href="/tags/detroit-edison">Detroit Edison</a><span class="pur_comma">, </span><a href="/tags/entergy">Entergy</a><span class="pur_comma">, </span><a href="/tags/epc">EPC</a><span class="pur_comma">, </span><a href="/tags/federal-communications-commission">Federal Communications Commission</a><span class="pur_comma">, </span><a href="/tags/ferc">FERC</a><span class="pur_comma">, </span><a href="/tags/florida-psc">Florida PSC</a><span class="pur_comma">, </span><a href="/tags/gas">GAS</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/general-electric">General Electric</a><span class="pur_comma">, </span><a href="/tags/ice">ICE</a><span class="pur_comma">, </span><a href="/tags/ipp">IPP</a><span class="pur_comma">, </span><a href="/tags/irg">IRG</a><span class="pur_comma">, </span><a href="/tags/iso">ISO</a><span class="pur_comma">, </span><a href="/tags/it">IT</a><span class="pur_comma">, </span><a href="/tags/madison-gas-and-electric">Madison Gas and Electric</a><span class="pur_comma">, </span><a href="/tags/massachusetts-municipal-wholesale-electric-co">Massachusetts Municipal Wholesale Electric Co.</a><span class="pur_comma">, </span><a href="/tags/nera">NERA</a><span class="pur_comma">, </span><a href="/tags/network">Network</a><span class="pur_comma">, </span><a href="/tags/new-jersey">New Jersey</a><span class="pur_comma">, </span><a href="/tags/pacificorp">PacifiCorp</a><span class="pur_comma">, </span><a href="/tags/pepco">PEPCO</a><span class="pur_comma">, </span><a href="/tags/portland-general-electric">Portland General Electric</a><span class="pur_comma">, </span><a href="/tags/potomac-electric-power">Potomac Electric Power</a><span class="pur_comma">, </span><a href="/tags/public-service-enterprise-group">Public Service Enterprise Group</a><span class="pur_comma">, </span><a href="/tags/qf">QF</a><span class="pur_comma">, </span><a href="/tags/rec">REC</a><span class="pur_comma">, </span><a href="/tags/res">RES</a><span class="pur_comma">, </span><a href="/tags/rgi">RGI</a><span class="pur_comma">, </span><a href="/tags/rochester-gas-electric">Rochester Gas &amp; Electric</a><span class="pur_comma">, </span><a href="/tags/southwest-power-pool">Southwest Power Pool</a><span class="pur_comma">, </span><a href="/tags/storage">storage</a><span class="pur_comma">, </span><a href="/tags/str">STR</a><span class="pur_comma">, </span><a href="/tags/technology">Technology</a><span class="pur_comma">, </span><a href="/tags/tep">TEP</a><span class="pur_comma">, </span><a href="/tags/tucson-electric-power">Tucson Electric Power</a><span class="pur_comma">, </span><a href="/tags/ubs">UBS</a><span class="pur_comma">, </span><a href="/tags/unisource-energy">UniSource Energy</a><span class="pur_comma">, </span><a href="/tags/ver">VER</a> </div>
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Sun, 15 Feb 1998 05:00:00 +0000puradmin9729 at https://www.fortnightly.comState Roundup - Electric Competition Moves Onhttps://www.fortnightly.com/fortnightly/1997/02-0/state-roundup-electric-competition-moves
<div class="field field-name-field-import-byline field-type-text-long field-label-inline clearfix"><div class="field-label">Byline:&nbsp;</div><div class="field-items"><div class="field-item even"><p>Lori A. Burkhart</p>
</div></div></div><div class="field field-name-field-import-volume field-type-node-reference field-label-inline clearfix"><div class="field-label">Magazine Volume:&nbsp;</div><div class="field-items"><div class="field-item even">Fortnightly Magazine - February 15 1997</div></div></div><div class="field field-name-body field-type-text-with-summary field-label-hidden"><div class="field-items"><div class="field-item even"><p> Electric Competition Moves On </p>
<p> The recent months have brought a flurry of activity in a number of states: </p>
<p> ARIZONA: The Arizona Corporation Commission approved rules opening Arizona's electric industry to competition over a four-year period starting in 1999. The rules allow retail customers to retain standard electric service, or to choose competitive services. </p>
<p> Beginning Jan. 1, 1999, utilities must make available 20 percent of its peak 1995 demand to all customers, including small business and residential. No more than 50 percent of that amount may be sold to large customers, and 15 percent of the total will be reserved for residential customers. </p>
<p> Starting on Jan. 1, 2001, 50 percent of a utilitiy's peak 1995 demand must be available competitively. Thirty percent of that total must be reserved for residential customers. Finally, on Jan. 1, 2003, 100 percent of the total electric supply will be available on the competitive market. </p>
<p> All electric companies will have to get commission approval to provide competitive services. Although early drafts of the commission's proposal excluded the Salt River Project from participating in the competitive market, SRP was allowed to participate by signing an intergovernmental agreement. However, a hearing regarding SRP, a municipality serving 635,000 customers, will be held prior to final approval. </p>
<p> Several issues remain to be decided, including how to deal with stranded-cost recovery. The commission is holding a series of workshops to decide such issues. </p>
<p> COLORADO: The Colorado Public Utility Commission released a 125-page electric restructuring report, which is a compilation of responses to a PUC questionnaire. The report, which is intended for information purposes only, was </p>
<p> distributed to legislators, the governor's office and members of the utility community. </p>
<p> "We've packaged the various perspectives into a single report to give the reader a broader and deeper understanding of what the issues are," said PUC Director Bruce Smith. Both the report and the 40 responses are available through the PUC Web site at <a href="http://www.puc.state.co.us">http://www.puc.state.co.us</a>. </p>
<p> GEORGIA: The Georgia Public Service Commission has decided to initiate a series of electric restructuring workshops starting in April to explore the issues that will be encountered in the move to a competitive environment. </p>
<p> It said that regulatory reform has not been as urgent in the southern states where electric rates historically have been lower than the national average. </p>
<p> "While we certainly have a lot on our plate in facilitating telephone competition and in deregulating the natural gas industry, it is important that we prepare for electric restructuring expected in the coming years," said PSC Chairman Dave Baker. </p>
<p> Meanwhile, the Georgia General Assembly is preparing to enact legislation deregulating the gas industry in the spring session. The Georgia House and Senate Gas Study Committees last December had issued their findings to the legislature. </p>
<p> INDIANA: Indiana state Rep. James Bottorff (D) and state Senator Morris Mills (R) have introduced legislation in the Indiana General Assembly allowing all customers to choose their electric suppliers by mid-2004. During a five-year transition period, electric rates either would be frozen or gradually lowered to a state average price. </p>
<p> Customers would choose their power supplier as early as Oct. 1, 1999, by paying a "market access charge." After Jan. 1, 1997, no new requests to increase base utility rates may be filed with the Indiana Utility Regulatory Commission. Quarterly fuel-price adjustments would continue until July 1, 1999. At that time, utility rates would be frozen. Utilities with rates above the state average would have to gradually lower their rates to a state average price between Oct. 1, 1999 and July 1, 2004. </p>
<p> Customers who do not select an electric supplier will have one designated for them by the commission. All electric generators and marketers must offer a "green" power option, which would allow consumers to choose an environmentally friendly supplier. Customers of Indiana's municipal and rural electric co-ops could vote to opt out of competition. </p>
<p> The bill has the support of American Electric Power, CINergy, Indiana Industrial Energy Consumers Inc., and Indiana Manufacturers Association. </p>
<p> MONTANA: Montana Power Co. has advised the Montana Public Service Commission on how to restructure the state's electric industry. A new docket was created to allow the Montana Legislature to review competitive issues first. </p>
<p> Montana Power proposes that Montana phase in competition during a transitional period through July 1, 2002, when all customers would have the opportunity to choose their electric supplier. A "universal systems benefits charge" would pay for low-income services, energy efficiency programs, renewable energy programs and research and development. A </p>
<p> competitive-transition charge would be imposed to pay for stranded costs. Generation would become unregulated and competitive. </p>
<p> The Montana PSC had conducted a roundtable hearing on restructuring early in 1996, and had issued its statement on principles for restructuring in May 1996. "We believe our informational filing addresses these principles, and becomes the first documented proposal offered in Montana to define a transition to electric power supply choice," said MP Vice Chairman and President Robert P. Gannon. </p>
</p>
<p> (em Lori A. Burkhart </p>
</p>
<p></p>
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<a href="/tags/american-electric-power">American Electric Power</a><span class="pur_comma">, </span><a href="/tags/commission">Commission</a><span class="pur_comma">, </span><a href="/tags/ge">GE</a><span class="pur_comma">, </span><a href="/tags/indiana-utility-regulatory-commission">Indiana Utility Regulatory Commission</a><span class="pur_comma">, </span><a href="/tags/rgi">RGI</a> </div>
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Sat, 15 Feb 1997 05:00:00 +0000puradmin9999 at https://www.fortnightly.com